[House Hearing, 110 Congress]
[From the U.S. Government Publishing Office]




  SPINNING STRAW INTO BLACK GOLD: ENHANCED OIL RECOVERY USING CARBON 
                                DIOXIDE

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

                           OVERSIGHT HEARING

                               before the

                       SUBCOMMITTEE ON ENERGY AND
                           MINERAL RESOURCES

                                 of the

                     COMMITTEE ON NATURAL RESOURCES
                     U.S. HOUSE OF REPRESENTATIVES

                       ONE HUNDRED TENTH CONGRESS

                             SECOND SESSION

                               __________

                        Thursday, June 12, 2008

                               __________

                           Serial No. 110-75

                               __________

       Printed for the use of the Committee on Natural Resources



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

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                     COMMITTEE ON NATURAL RESOURCES

              NICK J. RAHALL, II, West Virginia, Chairman
              DON YOUNG, Alaska, Ranking Republican Member

Dale E. Kildee, Michigan             Jim Saxton, New Jersey
Eni F.H. Faleomavaega, American      Elton Gallegly, California
    Samoa                            John J. Duncan, Jr., Tennessee
Neil Abercrombie, Hawaii             Wayne T. Gilchrest, Maryland
Solomon P. Ortiz, Texas              Chris Cannon, Utah
Frank Pallone, Jr., New Jersey       Thomas G. Tancredo, Colorado
Donna M. Christensen, Virgin         Jeff Flake, Arizona
    Islands                          Stevan Pearce, New Mexico
Grace F. Napolitano, California      Henry E. Brown, Jr., South 
Rush D. Holt, New Jersey                 Carolina
Raul M. Grijalva, Arizona            Luis G. Fortuno, Puerto Rico
Madeleine Z. Bordallo, Guam          Cathy McMorris Rodgers, Washington
Jim Costa, California                Louie Gohmert, Texas
Dan Boren, Oklahoma                  Tom Cole, Oklahoma
John P. Sarbanes, Maryland           Rob Bishop, Utah
George Miller, California            Bill Shuster, Pennsylvania
Edward J. Markey, Massachusetts      Bill Sali, Idaho
Peter A. DeFazio, Oregon             Doug Lamborn, Colorado
Maurice D. Hinchey, New York         Mary Fallin, Oklahoma
Patrick J. Kennedy, Rhode Island     Adrian Smith, Nebraska
Ron Kind, Wisconsin                  Robert J. Wittman, Virginia
Lois Capps, California               Steve Scalise, Louisiana
Jay Inslee, Washington
Mark Udall, Colorado
Joe Baca, California
Hilda L. Solis, California
Stephanie Herseth Sandlin, South 
    Dakota
Heath Shuler, North Carolina

                     James H. Zoia, Chief of Staff
                       Rick Healy, Chief Counsel
            Christopher N. Fluhr, Republican Staff Director
                 Lisa Pittman, Republican Chief Counsel
                                 ------                                

              SUBCOMMITTEE ON ENERGY AND MINERAL RESOURCES

                    JIM COSTA, California, Chairman
          STEVAN PEARCE, New Mexico, Ranking Republican Member

Eni F.H. Faleomavaega, American      Louie Gohmert, Texas
    Samoa                            Bill Shuster, Pennsylvania
Solomon P. Ortiz, Texas              Bill Sali, Idaho
Rush D. Holt, New Jersey             Adrian Smith, Nebraska
Dan Boren, Oklahoma                  Steve Scalise, Louisiana
Maurice D. Hinchey, New York         Don Young, Alaska, ex officio
Patrick J. Kennedy, Rhode Island
Hilda L. Solis, California
Nick J. Rahall II, West Virginia, 
    ex officio
                                 ------                                












                                CONTENTS

                              ----------                              
                                                                   Page

Hearing held on Thursday, June 12, 2008..........................     1

Statement of Members:
    Costa, Hon. Jim, a Representative in Congress from the State 
      of California..............................................     1
        Prepared statement of....................................     3
    Pearce, Hon. Stevan, a Representative in Congress from the 
      State of New Mexico........................................     4
        Prepared statement of....................................     6

Statement of Witnesses:
    Demchuk, Mark, Team Lead Weyburn, EnCana Corporation, 
      Calgary, Alberta, Canada...................................    51
        Prepared statement of....................................    53
        Response to questions submitted for the record...........    58
    Duncan, Dr. Ian, Associate Director, Earth and Environmental 
      Systems, Bureau of Economic Geology, University of Texas at 
      Austin.....................................................    48
        Prepared statement of....................................    49
    Evans, Ronald T., Senior Vice President of Reservoir 
      Engineering, Denbury Resources, Incorporated...............    25
        Prepared statement of....................................    27
        Response to questions submitted for the record...........    32
    Klara, Scott M., National Energy Technology Laboratory, U.S. 
      Department of Energy.......................................    13
        Prepared statement of....................................    14
        Response to questions submitted for the record...........    18
    Kunkel, Dr. Gregory P., Vice President, Environmental 
      Affairs, Tenaska, Inc......................................    40
        Prepared statement of....................................    42
        Response to questions submitted for the record...........    47
    Roby, William, Vice President, Worldwide Engineering and 
      Technical Services, Occidental Oil and Gas Corporation.....    34
        Prepared statement of....................................    36
        Response to questions submitted for the record...........    39
    Spisak, Timothy, Division Chief, Fluid Minerals, Bureau of 
      Land Management, U.S. Department of the Interior...........     8
        Prepared statement of....................................     9

Additional materials supplied:
    Peridas, George, Ph.D., Science Fellow, Climate Center, 
      Natural Resources Defense Council, Statement submitted for 
      the record.................................................    69

 
   OVERSIGHT HEARING ON SPINNING STRAW INTO BLACK GOLD: ENHANCED OIL 
                     RECOVERY USING CARBON DIOXIDE.

                              ----------                              


                        Thursday, June 12, 2008

                     U.S. House of Representatives

              Subcommittee on Energy and Mineral Resources

                     Committee on Natural Resources

                            Washington, D.C.

                              ----------                              

    The Subcommittee met, pursuant to call, at 10:08 a.m. in 
Room 1334, Longworth House Office Building, Hon. Jim Costa 
[Chairman of the Subcommittee] presiding.
    Present: Representatives Costa, Pearce, Holt, Sali, Smith, 
and Scalise.

   STATEMENT OF THE HONORABLE JIM COSTA, A REPRESENTATIVE IN 
             CONGRESS FROM THE STATE OF CALIFORNIA

    Mr. Costa. The oversight hearing of the Subcommittee on 
Energy and Mineral Resources will come to order. The 
Subcommittee is meeting today to hear testimony on enhanced oil 
recovery using carbon capture and sequestration. There has been 
a lot of discussion about this over the last several years, and 
there is proposed legislation that deals with the issue.
    It is appropriate and fitting, therefore, that the 
Subcommittee take an opportunity to have the various witnesses 
give us their take on the potential as it relates to a host of 
options in terms of the management toolbox for carbon 
sequestration for oil and gas recovery, as to the potential as 
it relates to carbon capture and sequestration.
    I have to do a few preliminaries before I and the Ranking 
Member get into our opening statements. They are the following.
    Under Rule 4(g), the Chairman and the Ranking Minority 
Member may make opening statements, which I guess we will do. 
If any Members have any other statements, we are interested in 
them, and they will be included in the record under unanimous 
consent.
    Additionally, under Committee Rule 4(h), additional 
material for the record should be submitted by Members or the 
witnesses within 10 days after the hearing. We ask you to 
really comply with that, and to help our staff, both the 
Majority and Minority staff.
    We would appreciate witnesses' cooperation in any written 
submission of questions to the witnesses, either in the first 
or second panel, if in fact questions are submitted by Members, 
that you respond in a timely fashion in writing within the 10 
days.
    Now, having settled all that, let me begin in terms of an 
opening statement for all of you here who are present.
    We are meeting today obviously to look at what are the 
current state-of-the-art practices, and what is the potential 
as it relates to enhanced oil recovery using carbon dioxide. 
This is one of those energy issues where I think there is 
agreement on both sides of the aisle, that there are not only 
current activities taking place, but activities that can be 
built on.
    Not only can this technology help increase our domestic 
production of oil, but in fact it is already doing an 
impressive job in many fields throughout the country. And at 
the same time, the carbon dioxide that otherwise would go out 
into the atmosphere is being placed where it doesn't have an 
impact on our air quality.
    In my own district, there is a focal point for enhanced oil 
recovery that really has been taking place for decades. First, 
for those of you who are not aware of the district that I 
represent, it goes from Fresno in the north all the way down to 
Bakersfield in the south. And some of the earliest oil fields 
in California were developed in the Kern County region.
    Since 1961, we have begun a significant effort in taking 
some of the older fields that were first developed at the turn 
of the 20th century, some 50, 60 years prior, and in the early 
sixties we began looking at innovative ways that we could 
enhance the recovery, and therefore the production, of those 
older fields.
    It first began with steam injection, taking the steam and 
impacting the viscosity of the thicker crude that was contained 
in the strata, and using the steam to loosen up that very heavy 
crude, and getting, in a more cost-effective fashion, the 
ability to recover that oil. As a result of that effort, that 
steam recovery, now for over four decades, we have had over 
270,000 barrels of oil per day come through many of the older 
fields in California because of enhanced recovery.
    But projects like steam obviously don't use carbon dioxide. 
And we see an opportunity here to use a new technology that has 
taken place in a number of areas.
    In the last two years there are over 21 new carbon dioxide 
EOR projects in the United States. I think that is good news 
for all sorts of reasons. Twenty-one new carbon dioxide EOR 
projects in the United States.
    All told, carbon dioxide EOR produces today in the United 
States 250,000 barrels of oil each day, which equates to 
roughly 5 percent of the U.S. oil production. And the potential 
for additional application, I think, is even greater.
    The Department of Energy has estimated that there are over 
80 billion barrels of oil in the United States that is amenable 
to carbon dioxide-enhanced oil recovery, using current 
technology. Advances in EOR technology, that number could 
double, it is believed by some to be as much as 160 billion 
barrels of domestic oil production.
    Many of these resources exist in fields that are already in 
operation, where there is infrastructure, not only including 
the wells, but including the pipelines and the roads. The 
infrastructure that is necessary to make carbon dioxide 
enhancement recovery work. These resources I think are 
important to evaluate, and to assess in terms of how we can 
expand that exploration.
    While discussing the benefit to domestic energy supply, we 
also need to be mindful of the benefit to the environment, 
because I think it is equally as important. This great example 
of taking something that is often thought of as a waste 
product--i.e., carbon dioxide--and using it beneficially I 
think bodes well for all of us. If we take carbon dioxide from 
human activities and make sure that it stays underground, we 
can get some benefits as it impacts the climate.
    The International Energy Agency has said that carbon 
capture and sequestration is critical to reducing carbon 
dioxide. Enhanced oil recovery can help capture and sequester a 
lot of carbon dioxide, up to 13 billion tons by some estimates.
    Still, the National Petroleum Council has recently put it, 
``Enhanced oil recovery using carbon dioxide has the potential 
to play a key role in the early commercialization of carbon 
capture and sequestration; and as such, will provide an 
important technology bridge to the extensive application of 
carbon sequestration.''
    I agree with that sentiment, and I believe that the future 
of carbon dioxide-enhanced oil recovery is a bright one, just 
as back in the sixties the use of steam injection into some of 
the older fields in Kern County allowed us to take that thick, 
heavier crude and reduce its viscosity to a point where we 
could enhance the recovery of those fields.
    I look forward to the testimony from our witnesses. And I, 
at this time, would like to yield to the gentleman from New 
Mexico, the Ranking Member of the Subcommittee, Mr. Pearce.
    [The prepared statement of Mr. Costa follows:]

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

    In these times of record oil and gas prices, there is near 
unanimous bipartisan agreement that one of the goals we need to focus 
on is providing timely relief for American consumers--consumers who are 
spending higher and higher percentages of their incomes to fill their 
gas tanks and cool their homes. However, each party has very different 
ideas about the best ways to accomplish that goal.
    I do not believe that either party has a monopoly on good sense 
when it comes to this issue. Both have ideas that are valid, and that 
need to be explored. As someone who feels that we need to come together 
to find common solutions to our energy problems, it is particularly 
encouraging to be able to find a subject that has so much appeal to 
both sides of the aisle. Carbon dioxide enhanced oil recovery is a win-
win: it has energy supply benefits and it has environmental benefits. 
Done right, it has the ability to significantly increase the amount of 
oil we produce domestically, while also acting as a bridge to the 
large-scale sequestration of carbon dioxide underground, which the 
International Energy Association has said is essential for reigning in 
future carbon dioxide emissions.
    Enhanced oil recovery (EOR) has a long and lustrous history in my 
part of California. The oldest operating enhanced oil recovery field in 
the United States is in Kern County, and after four decades is still 
injecting steam to produce over 33,000 barrels of oil per day. 
Traditional oil production only recovers about one-third of the oil 
originally in the ground, leaving a huge resource base that we would be 
foolish to ignore. And since those first days in Kern County, steam and 
carbon dioxide have helped to flush out billions of barrels of 
additional oil from California to Texas, from the Rockies to the Gulf 
Coast.
    While production from steam EOR has been declining in recent years, 
carbon dioxide EOR has been growing, to the point where it now produces 
nearly 250,000 barrels of oil per day, nearly 5% of total United States 
oil production. And there is plenty left to go after, too. The 
Department of Energy has estimated that with current technology, there 
are over 80 billion barrels of oil in existing fields that could be 
obtained with carbon dioxide enhanced oil recovery, and with 
technological advances, that number could double.
    Let me say that again: there are over 80 billion barrels of oil in 
existing fields that could be obtained with carbon dioxide enhanced oil 
recovery. That is 8 times the amount of oil estimated to be contained 
in the Alaska National Wildlife Refuge.
    But the problem for EOR, ironically, is a lack of carbon dioxide. 
While there are billion of tons of CO2 coming out of our 
power plants each year, we simply do not have the infrastructure in 
place to capture and direct it to oil fields. Instead, we drill for 
natural sources of carbon dioxide stored underground, or, to a lesser 
extent, we capture the carbon dioxide coming off natural gas plants, 
fertilizer plants, or other small industrial facilities, and then 
transport it over 3,500 miles of pipeline to get it where it is needed. 
This is, however, just a small fraction of what we would need to fully 
unlock the potential of EOR.
    There are other environmental benefits to carbon dioxide EOR 
besides the reduced emissions to the atmosphere. By focusing on those 
fields that have already been in production, we get to take advantage 
of existing infrastructure, like wells, pipelines, and roads, as well 
as ease the pressure to start drilling in new areas.
    Enhanced oil recovery will not be the solution to our carbon 
dioxide emission problem--estimates are that we could store roughly 13 
billion tons of carbon dioxide through EOR, but that is not nearly 
enough. Still, it provides a very strong incentive for power plants to 
capture and sell their carbon dioxide, and for pipeline operators to 
build the connections necessary to get the carbon dioxide from the 
plant to the field. Our ability to reduce emissions in the future may 
depend on us taking both of these steps, so to the extent that EOR can 
help get us to do those faster, we are far better off.
    As the National Petroleum Council's recent report titled ``Facing 
the Hard Truths about Energy'', noted, ``enhanced oil recovery using 
carbon dioxide has the potential to play a key role in the early 
commercialization of CCS [carbon capture and sequestration] and, as 
such, will provide an important technology bridge to more extensive 
carbon sequestration.''
    I wholeheartedly agree, and I look forward to the testimony from 
our witnesses.
                                 ______
                                 

 STATEMENT OF THE HONORABLE STEVAN PEARCE, A REPRESENTATIVE IN 
             CONGRESS FROM THE STATE OF NEW MEXICO

    Mr. Pearce. Thank you, Mr. Chairman. I appreciate your 
holding this hearing today. We are meeting at a time when gas 
prices are an unprecedented $4.05 a gallon. They are 
significantly higher in places like California and the District 
of Columbia.
    Every day Americans are paying a record portion of their 
income in energy costs. But when you go to the poorest states, 
like New Mexico--we are about 47th on the per capita income--we 
pay a significantly greater percentage of our incomes for 
gasoline, and so we are very acutely aware of the escalating 
price of energy.
    Today's hearing is going to focus on carbon sequestration 
for enhanced oil recovery. It is going to give us the chance to 
examine some of the important issues that face companies 
producing oil, and some of America's oldest oilfields, at the 
same time talking about the domestic challenges that we are 
going to face in producing the fuel that moves America and 
powers our economy. So we have kind of a two-pronged 
consideration.
    Carbon capture and sequestration on a commercial scale is 
still an unproven technology. The process of separating and 
capturing carbon during the production of energy remains cost-
prohibitive under current law.
    As we are going to hear today, implementation of the 
capture program on a coal power plant may consume nearly 25 
percent of the power generated by that plant. Those costs have 
to be calculated. The initial investment on that particular 
plant will increase the cost by nearly 50 percent during the 
construction, from $2 billion to $3 billion. These costs for 
energy production will be passed along to the consumers who 
purchase electricity generated in these facilities.
    Enhanced oil recovery is a technically challenged and 
costly process. I suspect I am the only Member of Congress who 
actually ran a business that was engaged in reclaiming old 
oilfields. My wife and I ran a fishing and rental tool company. 
We did repairs on these aging wells in Lee County, New Mexico, 
across the border in Texas, and now then we are watching with 
interest as CO2 is being used to extend the life of 
those wells. But we are also very familiar with the 
technological challenges that come with that.
    The process is not suited for all oilfields. You cannot go 
into just any oilfield and start injecting carbon dioxide. The 
process simply has to have the right formation to work, and it 
will not work across the spectrum of oilfields in America. It 
is important to note that enhanced oil recovery is no 
replacement for new oilfield development.
    While the EOR can extend the life of a field by 10, 20, or 
even 30 years, America's oil producers need access to new 
developments and new reserves to ensure that America has the 
resources to keep our economy moving forward. We have the 
resources here in America, but many of them are locked up, like 
the Outer Continental Shelf, ANWR, or simply banned from 
development, like oil shale in Colorado and Utah.
    This hearing will highlight that while EOR can help America 
keep producing oil, it does produce, it does need new oil, and 
it is not, the enhanced oil recovery is not a solution to our 
energy crisis.
    There is concern that this hearing may be the start of a 
process that would move legislation banning the mining of 
CO2 from natural sources. That would be very 
misguided. Since mined CO2 is never released into 
the atmosphere, such a step would only increase costs for 
companies engaged in the EOR, while having no impact on 
reducing atmospheric CO2 concentrations.
    I would hope that going forward, we can give the companies 
engaged in the process the confidence that they are not going 
to see their investments disrupted by misguided and misdirected 
legislation. We have already seen that in close detail on the 
conversion of corn to ethanol; we have seen the tremendous 
pressure on our water resources, now greater acres than ever 
are being plowed up in our rain forests. And finally, the 
conversion of food to fuel is causing hunger throughout the 
world.
    Finally, Mr. Chairman, while this hearing touches on the 
issue of domestic energy, it is not about actually producing 
new domestic energy. At a time when Americans are facing record 
energy costs, this committee has the responsibility to take 
steps to address how to increase domestic oil production and 
reduce costs.
    I would ask you, Mr. Chairman, to hold a hearing next week, 
where we are working together. We invite witnesses and talk 
about the specific steps we could take to increase domestic 
energy production, reduce our dependence on foreign oil, reduce 
gasoline costs for our constituents, and more importantly, help 
America get our economy moving forward.
    I hope you will consider my request. And I yield back, 
looking forward to the testimony that we hear from our 
witnesses today.
    [The prepared statement of Mr. Pearce follows:]

       Statement of The Honorable Steve Pearce, Ranking Member, 
              Subcommittee on Energy and Mineral Resources

    Mr. Chairman, thank you for holding this hearing today. This 
Committee is meeting at a time when Americans are facing record and 
rising gasoline costs. Yesterday, the national average for gasoline 
surpassed $4.05 a gallon, and is significantly higher in states like 
California and here in the District of Columbia.
    Everyday Americans are paying record portions of their income in 
energy costs. This burden is carried by poor and working citizens, like 
my constituents in New Mexico, at 47th in per capita income, who pay 
America's highest percentage of their income for energy costs.
    Today's hearing will focus on Carbon Sequestration for Enhanced Oil 
Recovery.
    This hearing will give us a chance to examine some of the important 
issues face companies producing oil on some of America's oldest oil 
fields. At the same time, talking about the domestic challenges they 
face in producing the fuel that moves America and powers our economy.
CARBON CAPTURE
    Carbon capture and sequestration on the commercial scale remains an 
unproven technology. The process of separating and capturing carbon 
during the production of energy remains cost prohibitive under current 
law. As we are going to hear today, implementation of a capture program 
on a coal power plant may consume nearly 25 percent of the power 
generated by that plant. The initial investment will increase the costs 
nearly 50%, from $2 Billion to $3 Billion, for the construction of the 
plant. These costs for energy production will be passed along to the 
consumers who purchase electricity generated in these facilities.
ENHANCED OIL RECOVERY (EOR)
    Enhanced oil recovery is a technically challenging and costly 
process. I am probably one on the only Members of Congress who has 
personal experience working in these older oil fields. My wife and I 
operated a fishing business which worked to repair wells in older oil 
fields, like those using to EOR. Near my home in Lea County, New 
Mexico, and across the border in Texas, this process is being used to 
extend the life of some of America's oldest oil fields.
    However, this process is not suited to all of America's oil fields 
and simply because the process works in Texas and New Mexico doesn't 
mean that it will work in every oil field in America. It is important 
to conduct EOR that you have the right underground formation.
AMERICAN RESOURCES
    It is also important to note that Enhanced Oil Recovery is no 
replacement for new oil field development. While EOR can extend the 
life of a field by 10, 20, maybe 30 years, America's oil producers need 
access to new development and new reserves to ensure that America has 
the resources to keep our economy moving forward.
    We have the resources here in America but many of them are locked 
up, like the OCS and ANWR or simply banned from development like the 
oil shale of Colorado and Utah. This hearing will highlight that while 
EOR can help America keep producing oil, it does need new oil, and is 
not a solution to our energy crisis.
LEGISLATION
    There is concern that this hearing may be the start of a process to 
move legislation banning the mining of CO2 from natural 
sources misguided. Since mined CO2 is never released into 
the atmosphere such a step would only increase costs for companies 
engaged in EOR while having no impact on reducing atmospheric 
CO2 concentrations. I would hope that going forward we could 
give the companies engaging in this process the confidence that they 
are not going to see their investments disrupted by misguided and 
misdirected legislation. We have seen this happen with the development 
of Ethanol, where we believed that we could grow our way to energy 
independence, instead we are facing water shortages, worldwide 
deforestation and growing hunger from rising food costs.
HEARING
    Finally, Mr. Chairman while this hearing touches on the issue of 
domestic energy; it is not about actually producing new sources 
domestic energy. At a time when Americans are facing record energy 
costs this committee has the responsibility to take steps to address 
how to increase domestic oil production and reduce costs.
    I would ask you Mr. Chairman to work with me to hold a fair hearing 
next week where working together we invite witnesses and talk about the 
specific steps we could take to increase domestic energy production, 
reduce our dependence on foreign oil, reduce gasoline costs for our 
constituents, and more importantly help America get our economy moving 
forward.
                                 ______
                                 
    Mr. Costa. Thank you very much, gentleman from New Mexico. 
Always willing to consider any requests and good ideas. I do 
believe, in fact, that there are multiple management tools in 
our energy toolbox to deal with our issue. And certainly our 
oil and gas production domestically, in terms of ensuring that 
we are as effective as we possibly can, is one of the issues 
that I support.
    We have increased application for permits to drill by 361 
percent, beginning at the end of the Clinton Administration and 
throughout the Bush Administration. Today there are over 28,000 
active application of permits to drill, and the energy 
companies that have bid on those application of permits to 
drill that have been approved through the Minerals Management 
Service are active on over 18,000, which means that there are 
over 10,000 that are currently not being utilized.
    But I believe that we need to examine all efforts. I was in 
the Gulf of Mexico several months ago, and there is tremendous 
activity taking place out there, as we all know, and the recent 
bids that have taken place. We have had record bids at that, on 
when they become available, for those companies that are 
participating in them. And that really reflects, I think, in 
part the desire on energy companies in our country to maximize 
our efforts for both onshore, as well as offshore, 
opportunities for oil and gas.
    And while I can tell you, because I know a little bit about 
my schedule next week, that we can't do that next week, it is a 
subject of something that I have been entertaining, because we 
do have an energy crisis in this country. I agree with you on 
that point. And it is not going to go away.
    And nor do I believe that there are any silver bullets, 
whether it is corn or anything of the list of menus that people 
have that have good ideas, and they are good ideas. But there 
is no one sole source of solutions. It is, in my view, a 
combination of solutions that are involved, short-term and 
long-term efforts. And if we are going to be successful, it is 
going to have to be done in a bipartisan way, in my opinion.
    So, to appropriately respond to your comments, and I hope I 
did, I think it is important that we get into the meat of this 
morning's hearing, which is part of this larger conversation.
    Let me say for those of you, we have been told that the 
schedule is as follows: that we are going to have votes around 
11:00. And so my desire is to have our first panel testify; 
have a round of questions to the first panel. I am not sure we 
are going to be able to do this, but I would like to then get 
to the second panel, and at least get the second panel to be 
able to all make their opening statements before we have to go 
and vote. I don't know how many votes we are going to have. 
Four votes.
    Four votes usually, for those of you who aren't familiar 
with our drill across the street, usually involves about 40 
minutes, or 30 to 40 minutes. So some time after 11:00 there 
will be a 30- to 40-minute break when we are forced, not 
forced, but when we are required to fulfill our other 
obligations, which is to vote on behalf of our constituencies.
    So with that understood, we will begin with our first 
panel.
    Mr. Timothy Spisak. Did I pronounce it right?
    Mr. Spisak. Spisak, yes.
    Mr. Costa. Spisak, is the Chief of Fluid Minerals Division 
of the Bureau of Land Management. And Mr. Scott Klara is also 
with us today, and we are looking forward to your testimony.
    I think you understand the drill. You have those lights in 
front of you. It is five-minute timing. The green light means 
that you have four minutes, and then when the yellow light goes 
on you are on your last minute. And we do try to stay within 
the timeframe of the five minutes allowed for your oral 
testimony. Obviously, if you have more lengthy testimony, that 
is submitted for the record.
    So let us begin, Mr. Spisak, with your testimony, please.

 STATEMENT OF TIMOTHY SPISAK, CHIEF, FLUID MINERALS DIVISION, 
                   BUREAU OF LAND MANAGEMENT

    Mr. Spisak. Mr. Chairman, members of the Subcommittee, 
thank you for the opportunity to be here today to discuss 
enhanced oil recovery using carbon dioxide on public land.
    As you mentioned, my name is Tim Spisak, Fluid Minerals 
Division Chief for the Bureau of Land Management, and I oversee 
the BLM's oil and gas program.
    My testimony today will address ongoing enhanced oil 
recovery efforts and future plans for large-scale carbon 
sequestration projects on public lands. Enhanced oil recovery, 
or EOR, is a process used to recover more oil than can be 
obtained by natural pressure, through the injection of fuel or 
gas, such as CO2, into an oil reservoir to force 
more to the surface.
    CO2 is a leasable commodity for which BLM 
collects royalties, and can be a byproduct of oil and gas 
production on public lands. The decision to undertake 
CO2 EOR is largely that of industry, and is 
generally guided by financial considerations which balance 
infrastructure needs and the cost of CO2 against the 
anticipated return to determine whether the investment is 
justified.
    Within the BLM's regulated authority to administer oil and 
gas leases, EOR is generally approved as part of a secondary 
unit agreement and sundry notices, in order to ensure that the 
company is moving forward in accordance with regulation and 
policy.
    Geological storage of carbon dioxide involves injection of 
CO2 into a subsurface rock unit, and displacement of 
the fluid or formation water that occupied the pore space. This 
principle operates in all types of potential geological storage 
formations, such as oil and gas fields, coalbeds, and deep 
saline water-bearing formations.
    Most of the potential CO2 storage capacity in 
the U.S. is in these deep saline formations. The BLM 
anticipates taking a leading role, working with other agencies, 
to evaluate and develop where appropriate long-term carbon 
sequestration efforts.
    The BLM is currently working with partners on demonstration 
projects, including a deep saline sequestration project in 
Utah, and an enhanced coalbed methane project in Mexico.
    The BLM existing administrative and regulatory structure 
will help facilitate future carbon sequestration projects, and 
potentially leasing. We expect these continuing efforts to lead 
to a robust, coordinated regulatory framework.
    The BLM's experience in administering a large-scale mineral 
leasing program, issuing rights-of-way on public land, and 
other programmatic and land-management expertise will 
facilitate this effort. As called for by the Energy 
Independence and Security Act, Section 714, the BLM is working 
in coordination with USGS, DOE, EPA, and others, to complete a 
report to Congress by December 2008, outlining a recommended 
framework for geologic sequestration on public lands.
    As long-term sequestration efforts advance, a number of 
issues will need to be addressed. These issues include the 
economics of geologic sequestration of man-made CO2, 
the feasibility and logistics of long-term geologic containment 
of CO2, the ownership of formation pore space on 
split-estate lands, the liability and safety issues related to 
potential release of CO2 stored underground, or 
potential saltwater intrusion into freshwater aquifers, and the 
degree of public acceptance of the construction and operation 
of nearby CO2 sequestration facilities.
    As the nation's largest Federal land manager, the BLM 
recognizes its responsibilities to the country, and the 
opportunity to play a key role in EOR and carbon capture and 
sequestration. I look forward to providing you the results of 
our efforts in December, and would be happy to answer any of 
your questions.
    [The prepared statement of Mr. Spisak follows:]

       Statement of Tim Spisak, Division Chief, Fluid Minerals, 
       Bureau of Land Management, U.S. Department of the Interior

Introduction
    Mr. Chairman and Members of the Subcommittee, thank you for the 
opportunity to be here today to discuss enhanced oil recovery using 
carbon dioxide on public lands. I am Tim Spisak, Division Chief for 
Fluid Minerals for the Bureau of Land Management (BLM), and I oversee 
the BLM's Oil and Gas program. My testimony today will address on-going 
enhanced oil recovery efforts and progress to date and future plans for 
large-scale carbon sequestration projects on public lands.
    BLM-managed public lands and minerals continue to play an important 
role in meeting the Nation's energy needs. Increases in energy prices 
are affecting the Nation as a whole. The BLM is looking to continue to 
facilitate the development of oil and gas resources on the public lands 
in addition to providing for alternative and renewable forms of energy 
in an environmentally-sound way.
    As the Nation's largest land manager, the BLM is entrusted with the 
multiple-use management of 258 million acres of land, and administers 
700 million acres of sub-surface mineral estate of which the surface 
owners are Federal agencies, states, or private entities. Of the 1.2 
billion acres inventoried by the U.S. Geological Survey (USGS) in its 
National Oil and Gas Assessment, 279 million acres are under Federal 
management. The recently released Energy Policy and Conservation Act 
(EPCA) Phase III Report found that these resources translate into 30.5 
billion barrels of undeveloped oil and 5.3 billion barrels of proven 
reserves. These areas currently under lease are the most likely for 
enhanced oil recovery in the short term.
    In 2007, nearly 3,500 new oil and gas leases were issued and 
approximately 500 of the more than 5,340 wells spud on over 4.6 million 
acres of leased Federal land were for oil production. We are diligent 
in executing our responsibilities to make these resources available in 
an environmentally-sound manner. Within the framework of a transparent 
public process, we carefully consider any potential effects to habitat, 
groundwater, air and other resources; mitigate impacts through best 
management practices, stipulations and conditions of approval; and 
balance development with other uses across the landscape. It is our 
role, with the appropriate environmental protections in place, to 
provide the tools needed to allow oil production from leased resources, 
to facilitate the pioneering of new technology, and to ensure a fair 
return to the American taxpayer from the development of resources from 
public lands.
    Escalating oil prices affect not only interest in domestic 
production, but also the viability of industry to pursue unconventional 
and renewable fuels through advanced technologies and processes. New 
technologies may allow industry to effectively recover resources that 
were once determined to be too expensive to pursue. Continuing to 
support and advance these efforts, in part, is essential to addressing 
the energy issues we now face.
Enhanced Oil Recovery
    Enhanced oil recovery (EOR) is a process used to recover more oil 
than can be obtained by natural pressure, through the injection of 
fluid or gas into an oil reservoir to force more oil to the surface. 
Carbon dioxide injection is one type of EOR. This process is often 
undertaken in the later stages of an oil and gas operation, but may be 
done at an earlier stage. The decision to undertake enhanced oil 
recovery is largely that of industry, and is generally guided by 
financial considerations. Industry balances infrastructure and the cost 
of carbon dioxide (or other medium) against the anticipated return to 
determine whether the investment is justified. Within the BLM's 
regulatory authority to administer oil and gas leases, EOR is generally 
incorporated into a ``sundry notice'' in order to ensure that the 
company is moving forward in accordance with the appropriate rules, 
regulations, and policies. An example of currently operating carbon 
dioxide EOR on Federal lands is the Salt Creek Field, a relatively 
shallow field in Wyoming that was developed in the early 1900's. In 
more recent times, it has become cost effective for industry to re-
develop this field using modern technology and extract resources left 
behind after earlier efforts. Following substantial reconstruction of 
existing infrastructure, carbon dioxide injection EOR has been 
employed, effectively doubling production. In the process, 150 million 
cubic feet of carbon dioxide is injected per day that would otherwise 
have been vented to the atmosphere.
    In addition to its use in enhancing oil recovery, carbon dioxide is 
a leasable commodity under the Mineral Leasing Act of 1920. The BLM 
currently collects revenues in the form of royalties derived from the 
sale of carbon dioxide produced in connection with oil and gas 
production on public lands. In 2007, the sale of carbon dioxide 
generated over $23 million in royalty revenue in the states of 
Colorado, New Mexico, and Wyoming.
    EOR's use of carbon injection will continue to yield valuable data 
and information that facilitates future efforts to effectively capture 
and sequester carbon dioxide in geologic formations found on public 
lands. A critical issue for evaluation of storage capacity is the 
integrity and effectiveness of these formations for sealing carbon 
dioxide underground, thereby preventing its release into the 
atmosphere. Current EOR efforts will enhance our understanding of these 
types of critical scientific and geologic issues. We expect that new 
information on this technology and the issues it presents will continue 
to be generated from activities on the public lands that we manage. As 
such, we anticipate the need for BLM to play an important role in 
collaborating with other Federal agencies, states, the private sector, 
and the public as we move forward in addressing legal and policy issues 
that arise during development.
Carbon Capture and Sequestration (CCS)
    The current atmospheric carbon dioxide concentration is 
approximately 380 parts per million volume and rising at a rate of 
approximately 2 parts per million volume annually, according to the 
most recent information from the Intergovernmental Panel on Climate 
Change (IPCC). The 2005 IPCC Special Report on Carbon Dioxide Capture 
and Storage concluded that in emissions reductions scenarios striving 
to stabilize global atmospheric carbon dioxide concentrations at 
targets ranging from 450 to 750 parts per million volume, the global 
storage capacity of geologic formations may be able to accommodate most 
of the captured carbon dioxide. However, it is not known how much of 
this carbon dioxide storage capacity would be economically feasible 
(assuming some price on carbon). Also, geologic storage capacity may 
vary widely on a regional and National scale. A more refined 
understanding of geologic storage capacity is needed to address these 
knowledge gaps.
    The challenges of addressing carbon dioxide accumulation in the 
atmosphere are significant. Fossil fuel usage, a major source of carbon 
dioxide emissions to the atmosphere, will continue for the foreseeable 
future in both industrialized and developing nations. Therefore, a 
variety of strategies are being investigated to reduce emissions and 
remove carbon dioxide from the atmosphere. Such strategies include the 
facilitated sequestration of carbon for the capture and storage of 
carbon dioxide through terrestrial sequestration using soils and trees, 
or by injection into geologic formations.
    Geological storage of carbon dioxide in porous and permeable rocks 
involves injection of carbon dioxide into a subsurface rock unit and 
displacement of the fluid or formation water that initially occupied 
the pore space. This principle operates in all types of potential 
geological storage formations such as oil and gas fields, deep saline 
water-bearing formations, or coal beds. Most of the potential carbon 
dioxide storage capacity in the U.S. is in deep saline formations.
    The BLM anticipates taking a leadership role, in collaboration with 
other agencies, in evaluating and developing, where appropriate, long-
term carbon sequestration efforts. The BLM's existing administrative 
and regulatory framework will help facilitate future carbon 
sequestration demonstration projects and potentially, leasing, and 
ultimately inform a robust, coordinated regulatory regime. In addition 
to experience in administering a large-scale mineral leasing program, 
we have the realty expertise and an existing framework for issuing 
rights-of-way on public land that could serve future needs for carbon 
dioxide pipelines across public lands. Other programmatic and land 
management expertise, such as the BLM's experience in evaluation of 
potential environmental impacts of projects, will facilitate this 
effort. Other agencies, such as USGS, DOE, and EPA will also play an 
important role in recommending geologic criteria that could be 
incorporated into a set of ``best practices'' for geologic site 
selection. The BLM looks forward to working closely with the USGS, DOE, 
EPA, the National laboratories, other Federal agencies, academia, 
industry and the public to develop geologic and technical criteria that 
could be used in future site selection.
    At this early stage in the development of carbon dioxide storage 
technologies, especially in the absence of large-scale demonstration 
projects of more than 1 million tons of carbon dioxide per year, many 
unknown factors may impact the development of best practices. We look 
forward to working together to resolve outstanding legal and policy 
questions as we continue to learn more about the technologies and 
geologic information necessary in moving forward with a carbon 
sequestration program. We understand that the Environmental Protection 
Agency (EPA) plans to propose regulations for issuing Safe Drinking 
Water Act permits for geologic sequestration of carbon dioxide. BLM 
will provide input as appropriate in the rulemaking process.
    Current CCS Demonstration Projects--The BLM is working with the 
Department of Energy (DOE) on regional partnerships that promote CCS 
demonstration projects. In promoting CCS efforts on public lands, the 
BLM is currently active in two demonstration projects: a deep saline 
sequestration project in Farnham Dome, Utah, and an enhanced coalbed 
methane project in San Juan Basin, New Mexico.
      The Farnham Dome project involves the reinjection and 
storage over a four year period of carbon dioxide produced on state and 
Federal lands with site monitoring for an additional 5 years. As a cost 
incentive for the demonstration project, the BLM has agreed to defer 
royalty payments on carbon dioxide produced from the Federal mineral 
estate (90 percent of the project area) until after the demonstration 
project when the carbon dioxide may be produced for commercial gain.
      The San Juan Basin project will demonstrate the 
feasibility of carbon dioxide coalbed sequestration while determining 
the potential for enhanced recovery of coalbed methane by injecting 
75,000 tons of carbon dioxide into the formation over a one-year 
period.
    We look forward to evaluating the results of these projects and to 
using these results to explore additional demonstration projects on 
public lands. If appropriate, we will begin looking at the costs and 
benefits of moving forward to develop a program for public lands. As 
the largest Federal land manager, the BLM will continue to support 
these demonstration projects, as well as other demonstration project 
opportunities that may be identified involving resources managed by the 
BLM.
Energy Independence and Security Act
    The BLM is currently implementing the carbon capture and storage 
provisions of the Energy Independence and Security Act (EISA) [Public 
Law 110-140]. Section 713 of EISA directs the BLM to maintain records 
on, and an inventory of, the quantity of carbon dioxide stored within 
Federal mineral leaseholds. The BLM is reviewing its current data 
collection structures and methods, including commercially available 
data, and will determine how this new data collection requirement can 
be incorporated into existing systems. The BLM is coordinating with the 
Minerals Management Service on changes that may be required to the Oil 
and Gas Operations Report that is used to collect production and 
injection data on Federal mineral estate.
    Section 714 of the EISA directs the Secretary of the Interior to 
submit a report to Congress by December 2008 containing a recommended 
framework for geological sequestration on public lands. In coordination 
with the Environmental Protection Agency, the Department of Energy, 
USGS, and other appropriate agencies, the BLM is examining criteria for 
identifying candidate geological sequestration sites in several 
specific types of geological settings. Additionally, the BLM will 
consider the EPA proposed regulations for carbon capture and 
sequestration when available to ensure that all of the BLM's 
recommendations are in compliance with the Safe Drinking Water Act and 
regulations under that Act. The BLM will be considering a regulatory 
framework for the leasing of public lands for the long-term geological 
sequestration of carbon dioxide, while providing for public review and 
protecting the quality of natural and cultural resources.
Future Efforts
    As the BLM advances long-term carbon sequestration efforts, several 
issues need to be addressed. Federal leasehold or Federal mineral 
estate liability issues related to the release of carbon dioxide stored 
underground will need to be studied and evaluated. Relevant experiences 
from enhanced oil recovery using carbon dioxide on public lands will 
assist us in examining this issue. In addition to scientific and 
geologic issues, legal and regulatory issues remain, specific to carbon 
dioxide sequestration on land in cases in which title to mineral 
resources is held by the United States, but title to the surface estate 
is not.
    In preparing our report to Congress under EISA, the BLM will 
examine existing statutes, regulations, proposed regulations, and case 
law, and recommend whether additional legislation may be necessary to 
ensure that public land management and leasing laws are sufficient to 
accommodate the long-term geological sequestration of carbon dioxide on 
public lands.
    In the meantime, the BLM plans to participate and expand its 
involvement in carbon dioxide research, development and demonstration 
projects. We will also continue to permit enhanced oil recovery 
operations on public land; analyze the data we are beginning to collect 
under Section 713 of EISA; examine the adequacy of existing regulations 
and proposed regulations; and move forward on other recommendations 
that will be developed over the next six months.
Conclusion
    Addressing the challenges of reducing atmospheric carbon dioxide 
and understanding the effects of global climate change are complex 
issues with many interrelated components. Geologic sequestration of 
carbon dioxide is one of several mechanisms being investigated by the 
scientific community. While promising, a number of unknowns remain.
      Existing demonstration projects have studied injection of 
carbon dioxide of geologic origin rather than atmospheric carbon 
dioxide. The economics of capturing and sequestering carbon dioxide 
from other sources are not well understood.
      Significant technological, scientific, and logistical 
challenges remain in geologic carbon sequestration, such as the ability 
to evaluate formations for containment capabilities over long periods 
of time, measured in hundreds or thousands of years. However, large 
scale demonstration projects such as those described earlier in my 
testimony will begin to address these challenges.
      Complex questions on access, compensation, and ownership 
of formation pore space on split-estate lands have not yet been 
resolved.
      Abandoned wells in proximity to injection sites often are 
not able to contain pressure increases associated with carbon dioxide 
injection, and can require substantial re-engineering.
      Liability and safety questions in the event of carbon 
dioxide leakage or salt water intrusion into fresh water aquifers are 
unresolved, although research jointly sponsored by EPA and DOE is 
underway to assess these issues.
      The degree of public acceptance of the construction and 
operation of nearby carbon dioxide sequestration facilities is unknown.
    The assessment activities required by the BLM in EISA should 
ultimately increase the information base upon which decision makers 
will rely as they deal with these issues. In addition to addressing the 
challenges presented by carbon dioxide, this commodity presents certain 
opportunities for future knowledge and use. The BLM stands ready to 
assist Congress as it examines these challenges and opportunities.
    The BLM will continue to support our Nation's energy needs and 
facilitate the pioneering of new technology and processes. As the 
Nation's largest Federal land manager, the BLM recognizes its 
responsibilities to the country and the opportunity to play a key role 
in enhanced oil recovery and carbon capture and sequestration. I look 
forward to providing you with the results of our efforts this December. 
I would be happy to answer your questions.
                                 ______
                                 
    Mr. Costa. Thank you very much, Mr. Spisak. And you stayed 
within the five minutes. We usually give gold stars for that.
    Our next witness, and I misspoke earlier, is Mr. Scott 
Klara with an L, not Kara, and I apologize for my misspeak, 
Director of the Strategic Center for Coal with the National 
Energy Technology Laboratory, which is a part of the Department 
of Energy.
    So Mr. Klara, please begin your testimony.

STATEMENT OF SCOTT KLARA, DIRECTOR, STRATEGIC CENTER FOR COAL, 
             NATIONAL ENERGY TECHNOLOGY LABORATORY

    Mr. Klara. Thank you, Mr. Chairman and members of the 
Subcommittee. It is a pleasure to be here.
    I appreciate the opportunity to provide testimony on the 
U.S. Department of Energy's research efforts in enhanced oil 
recovery using carbon dioxide; and in particular, its relevance 
to carbon sequestration.
    Throughout my brief remarks, I will refer to carbon dioxide 
as CO2, and enhanced oil recovery as EOR.
    Mr. Costa. That works for us.
    Mr. Klara. Although much of the nation's original onshore 
oil resource reserves have been produced, the Nation is still 
home to a large resource of oil. Large volumes of oil remain 
stranded in the reservoir. In fact, as much as 70 percent of 
the oil in the reservoir remains stranded due to technical and 
economic hurdles associated with primary extraction methods.
    Extraction of a significant fraction of the stranded oil is 
possible through the advances of technology related to 
CO2 EOR.
    Fossil fuel combustion and fossil fuel power plants in 
particular are a major source of CO2 emissions of 
potent greenhouse gas. In fact, fossil fuel power generation 
accounts for more than one-third of the U.S. anthropogenic 
greenhouse gas emissions, and CO2 in particular 
accounts for 80 percent of all U.S. greenhouse gas emissions.
    There is some good news. And that good news is that 
technologies are under development that can potentially provide 
significant reductions in CO2 emissions from fossil-
fueled power plants.
    Now, what if we were to try to tie these two challenges 
together: Increasing domestic oil recovery and reducing 
CO2 emissions from fossil-fueled power plants? This 
coupling becomes possible by the topic of this hearing, which 
is linking the capture of carbon CO2 from sources 
like power plants, and using this CO2 for EOR.
    The Department has recognized the importance of 
CO2 EOR for more than 40 years. Since the 1970s, 
DOE-funded projects have been developing concepts to improve 
the effectiveness and applicability of CO2 EOR.
    Current EOR research has begun to focus now on the carbon 
storage aspect of the process. In parallel with these 
developments, the Department also conducts research on future 
energy conversion technologies that will minimize 
CO2 emissions by developing cost-effective 
approaches for efficiently capturing CO2 from 
fossil-fueled power plants, and safely and permanently storing 
these in underground formations.
    Several key areas that make up this research program are 
sub-elements like gasification, advanced turbines, fuel cells, 
carbon capture, and sequestration. My written testimony has 
more detail about those program areas.
    I would like to now briefly elaborate a bit more on one key 
research program, the carbon sequestration program.
    Carbon sequestration developments are addressing the key 
challenges that confront the widescale deployment of capture-
and-storage technology through research on several areas: Cost-
effective capture technologies, monitoring, mitigation and 
verification technologies to ensure permanent storage, 
permitting issues, liability issues, public outreach, and 
infrastructure needs.
    Relative to EOR, the program is focusing on technologies 
for monitoring, mitigation, and verification that will validate 
permanent CO2 storage and EOR applications, and 
provide the necessary tools and best-practice protocols for 
using EOR as a carbon storage option. The Department's 
sequestration program was recently recognized by the EIA 
greenhouse gas group as the world's most ambitious program 
dedicated to the advancement of carbon-capture and storage 
technologies.
    My written testimony provides many facts, data, and 
references that highlight the potential of CO2 EOR 
and its relationship to CO2 storage. CO2 
EOR represents an early opportunity for helping to realize 
carbon-capture and sequestration technologies. Developing the 
technology base to support a widespread expansion of 
CO2 EOR could substantially increase existing United 
States oil reserves and oil production.
    The Department's developmental efforts are providing the 
elements necessary to help enable this expansion by advancing 
carbon-capture and storage technologies to increase the supply 
of carbon dioxide, and optimizing EOR technologies for carbon 
sequestration co-benefits.
    This completes my statement, and I look forward to 
additional discussion. Thank you.
    [The prepared statement of Mr. Klara follows:]

  Statement of Scott M. Klara, National Energy Technology Laboratory, 
                       U.S. Department of Energy

    Thank you, Mr. Chairman and members of the Subcommittee. I 
appreciate this opportunity to provide testimony on the U.S. Department 
of Energy's (DOE's) research efforts in enhanced oil recovery (EOR) 
using carbon dioxide (CO2) and its relevance to carbon 
sequestration.
Introduction
    The economic prosperity of the United States over the past century 
has been built upon an abundance of fossil fuels in North America. The 
United States' fossil fuel resources represent a tremendous national 
asset. Making full use of this domestic asset in a responsible manner 
enables the country to fulfill its energy requirements, minimize 
detrimental environmental impacts, and positively contribute to 
national security.
    The Nation is home to a large resource of oil. Although much of the 
Nation's original onshore petroleum reserves have been produced, large 
volumes of crude oil remain stranded in place after current production 
operations are completed because their extraction using current 
technology is both technically difficult and uneconomic. As much as 70% 
of the oil in a given reservoir remains stranded in place after current 
production operations are completed due to technological and economic 
hurdles. The total volume of this stranded oil 1 is 
estimated by Advanced Resources International (ARI), of Washington, DC, 
to exceed 390 billion barrels, though DOE and the U.S. Geological 
Survey (USGS) have not yet validated the ARI estimates. Of this total, 
ARI estimates that roughly 200 billion barrels are relatively 
accessible at depths to 5,000 feet below the surface. Extraction can be 
aided technically and made more economic through the use of 
CO2 for EOR. To put these numbers in context, according to 
the Energy Information Administration (EIA), we have produced about 195 
billion barrels of our petroleum resources over the past 120 years and 
currently have proven reserves 2 of roughly 21 billion 
barrels. Proven reserves are those quantities of petroleum, which, by 
analysis of geoscience and engineering data, can be estimated with 
reasonable certainty to be commercially recoverable, from a given date 
forward, from known reservoirs and under defined economic conditions, 
operating methods, and government regulations. If probabilistic methods 
are used, there should be at least a 90% probability that the 
quantities actually recovered will equal or exceed the estimate. 
Stranded oil is not currently included in proven reserves. Stranded oil 
is a resource that could add substantially to reserves when technology 
becomes available and economic conditions allow. It is equal to the 
total reserves in place, minus the proven reserves.
---------------------------------------------------------------------------
    \1\ Assessing Technical and Economic Recovery of Oil Resources in 
Residual Oil Zones, ARI, February 2006, www.adv-res.com/pdf/
ROZ_Phase_II_Document.pdf.
    \2\ U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 
2006 Annual Report, DOE/EIA-0216(2007), November 2007, www.eia.doe.gov/
oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/
cr.html.
---------------------------------------------------------------------------
    There is also scientific consensus that increased levels of 
greenhouse gases in the atmosphere, primarily CO2, methane, 
nitrous oxide, and chlorofluorocarbons, are linked to climate change. 
Globally, about 75-80% of total greenhouse gas emissions are 
CO2. In this connection, fossil fuel combustion, in general, 
and fossil-fuel power plants, in particular, have been identified as a 
major source of anthropogenic greenhouse gas emissions, particularly 
CO2, into the atmosphere. Slowing the growth of 
anthropogenic greenhouse gas emissions has become an important concern.
    Both of these challenges--extending the supply of domestic fuels 
(primarily oil) and reducing emissions of CO2 from fossil-
fueled power plants (primarily those fired with coal)--can be addressed 
simultaneously through the use of captured CO2 for achieving 
EOR. Currently, most EOR projects rely on the availability of cheap 
sources of naturally occurring CO2. If research into 
reducing the cost of CO2 capture from power plants proves 
successful, anthropogenic sources of CO2 may become readily 
available for EOR projects. The Intergovernmental Panel on Climate 
Change has estimated a worldwide technical capacity for CO2 
storage in EOR applications at 61 to 123 billion tonnes of 
CO2. Estimates by ARI, which DOE has not yet fully 
evaluated, have shown that the technical limit for CO2 
storage associated with EOR is 20 billion tons. Of that quantity, ARI 
estimates up to 12 billion tons could be economically stored, if EOR 
technology continues to advance and the cost of carbon capture 
technology is significantly reduced. If these potentials can begin to 
be realized, incremental oil produced via EOR using CO2 
flooding could help offset the costs of CO2 capture, and the 
prospect of relatively low-cost supplies of captured CO2 in 
widespread areas of the country could, in turn, provide the impetus for 
a national re-evaluation of the EOR potential in many mature fields. 
The proximity of sources of captured CO2 to oil reserves 
amenable to EOR is an important consideration, because transportation 
of CO2 over long distances is expensive and can affect the 
economics of EOR. The use of EOR for carbon sequestration will also 
involve permitting issues, liability issues, monitoring and 
verification technologies to ensure permanent storage, and public 
outreach.
    In summary, while conventional EOR is a commercial process, 
CO2 capture from coal power systems is not yet commercial at 
the large scale required for deployment in power plants. Continued 
evolution of EOR and transformational advances in development and 
deployment of CO2 capture from coal power could help realize 
this synergy between the coal/power industry and the oil industry.
Technology Developments
    The Department has recognized the importance of CO2 EOR 
for more than forty years. As early as the 1970s, DOE-funded projects 
were assessing the fluid properties of CO2 to establish its 
applicability in EOR. A special focus was given to developing 
correlations that helped the oil industry utilize these properties to 
improve EOR performance in commercial projects. Technological advances 
included the use of horizontal wells for improved reservoir contact, 
four-dimensional seismic to monitor the behavior of CO2 
floods, automated field-monitoring systems for detecting problems, and 
the injection of increasingly larger volumes of CO2 to 
increase recovery rates. This DOE-funded research has helped to 
significantly advance industrial EOR operations, most of which 
currently use CO2 from natural reservoirs, but the research 
focus is now on the carbon sequestration aspect of EOR, a developing 
application, rather than the mature oil production side of EOR.
    Coupled with these advances in CO2 EOR, the Office of 
Fossil Energy's Clean Coal Research & Development (R&D) Program 
provides for the development of new cost- and environmentally-effective 
approaches to coal use. The major focus of the program is developing 
future plant configurations that minimize CO2 emissions by 
developing cost-effective approaches for efficiently capturing 
CO2 from coal-fired plants, and safely and permanently 
sequestering the captured CO2 in underground reservoirs. The 
key technology areas that make up the Clean Coal R&D Program are 
discussed in the following paragraphs.
    Gasification is a pathway to convert coal or other carbon-
containing feedstocks into synthesis gas. This synthesis gas, in turn, 
can be used as a fuel to generate electricity or steam, or as a basic 
raw material to produce hydrogen, high-value chemicals, and liquid 
transportation fuels. The Advanced Integrated Gasification Combined 
Cycle Program is developing advanced gasification technologies to meet 
the most stringent environmental regulations and facilitate the 
efficient capture of CO2 for subsequent sequestration. 
Gasification plants are very amenable to CO2 capture because 
they can be designed to produce a high-pressure stream of 
CO2 that is easier to capture, compared to conventional 
power plant technologies. Advances in the current state-of-the-art, as 
well as the development of novel approaches, could provide the 
technical pathways enabling gasification to meet the demands of future 
energy markets, while minimizing greenhouse gas emissions.
    The Advanced Turbine Program consists of a portfolio of laboratory 
and field R&D focused on performance-improvement technologies with 
great potential for increasing efficiency and reducing emissions and 
costs in coal-based applications. The Program focuses on the combustion 
of pure hydrogen fuels in large-scale turbines greater than 100-
megawatt size range, and it has also worked on the development of less 
costly approaches for compressing large volumes of CO2. 
Since advanced turbines will be fuel-flexible, capable of operating on 
hydrogen or syngas, they will make possible electric power generation 
in gasification applications configured to capture CO2.
    Fuel Cells hold great potential to provide substantial improvements 
to the efficiency and emission reductions of future power plants. Fuel 
cell emissions per unit of electric power produced are well below 
current and proposed environmental limits for commercial power sources. 
Their modular nature permits use in central or distributed generation 
with equal ease. Rapid response to emergent energy needs is enhanced by 
the modularity and fuel flexibility of fuel cells. The ultimate goal of 
the program is the development of low-cost, megawatt-scale fuel cell 
power systems that will produce affordable, efficient, and clean 
electric power both as stand-alone sources, or when they are 
incorporated into integrated coal gasification combined-cycle systems 
equipped with CO2 capture and sequestration.
    Carbon sequestration developments are addressing the key challenges 
that confront the wide-scale deployment of capture and storage 
technologies through research on cost-effective capture technologies; 
monitoring, mitigation, and verification technologies to ensure 
permanent storage; permitting issues; liability issues; public 
outreach; and infrastructure needs. For example, relative to capture 
costs, today's commercially available capture and storage technologies 
will add around 80% to the cost of electricity for a new pulverized 
coal plant, and around 35% to the cost of electricity for a new 
advanced gasification-based plant. 3 The Carbon 
Sequestration Program is aggressively pursuing developments to reduce 
these costs to less than a 10% increase in the cost of electricity for 
new gasification-based energy plants, and is developing a goal for 
pulverized-coal energy plants. Relative to EOR, the program is focusing 
on technologies for monitoring, mitigation, and verification that will 
validate permanent CO2 storage in these applications, and 
provide the necessary best practices protocols for using EOR as a 
carbon storage option.
---------------------------------------------------------------------------
    \3\ 3 Cost and Performance Baseline for Fossil Energy Plants, 
Volume 1: Bituminous Coal and Natural Gas to Electricity, U.S. 
Department of Energy/National Energy Technology Laboratory, DOE/NETL-
2007/1281, Final Report, May 2007.
---------------------------------------------------------------------------
EOR and Sequestration Potential
    Many EOR processes incorporating thermal, chemical, microbial, and 
a variety of miscible gas-injection methods have been employed in the 
United States. Among these, CO2EOR is likely the most 
promising technology. Because CO2 is miscible with crude oil 
under certain conditions, it can be injected into previously drained 
oil reservoirs and used to sweep a portion of the remaining oil from 
the reservoir, thereby helping to overcome the physical forces that 
trap the residual oil. While not all of the relatively easily 
accessible stranded oil is susceptible for recovery by CO2-
EOR, a large proportion could be recovered if a source of low-cost 
CO2 and advanced CO2-EOR technologies are 
developed and deployed.
    A series of CO2-EOR assessments conducted by ARI have 
projected that, if current high oil prices are sustained over the long-
term, if low-cost captured CO2 from power plants is 
available, and if there continue to be improvements in CO2-
EOR technology, 89 billion barrels of incremental oil--more than four 
times the current U.S. proved reserves--may be economic to produce. It 
was also noted in this study that widespread use of improved 
CO2-EOR technologies and modified processes that emphasize 
using increased volumes of CO2 in each reservoir could 
result in three times as much CO2 being used, and five times 
more oil being recovered. These changes could result in significant 
recovery of this incremental oil. Since oil companies take many factors 
and risks into consideration when determining which investments to 
make, it is unlikely that all of the additional 89 billion barrels of 
domestic oil would be produced, due to the complexities of corporate 
investment decisions. DOE has not yet fully evaluated these projections 
and their relevance to DOE activities.
    ARI estimates that within just the large fields in North Dakota's 
portion of the Williston Basin, as much as 390 million barrels of 
incremental oil could have a cost of production less than the current 
price of oil, though DOE and USGS have not yet verified these 
estimates. In addition, the feasibility of converting the large 
unconventional in-place resource within the Bakken Shale of North 
Dakota into economic reserves has been examined by USGS. Their recent 
study estimates that nearly 4 billion barrels of (undiscovered) oil are 
technically recoverable from the Bakken Shale formation 4. 
Additionally, a 2006 study by the North Dakota Geological Survey, which 
DOE and USGS have not yet verified, suggested that by using next 
generation CO2-EOR technology, as much as 400 billion 
barrels, or more, of oil resource may be in-place 5. If 
injection of CO2 into this fractured shale could mobilize 
even a minor portion of this larger estimate, the Williston Basin's 
contribution to the Nation's oil supply would be significantly 
expanded.
---------------------------------------------------------------------------
    \4\ USGS, Assessment of Undiscovered Oil Resources in the Devonian-
Mississippian Bakken Formation, Williston Basin Province, Montana and 
North Dakota, April 2008.
    \5\ Bakken Formation Reserve Estimates, Julie LeFever and Lynn 
Helms, North Dakota Geological Survey, 2006.
---------------------------------------------------------------------------
    In addition, while the main focus of CO2-EOR is on 
maximizing the amount of oil produced rather than the amount of 
CO2 injected, its sequestration potential is still 
significant, though much less than the sequestration potential of 
saline formations in the United States. Estimates by ARI, which DOE is 
evaluating, have shown that the technical limit for CO2 
storage associated with EOR is 20 billion tonnes. Of that quantity, up 
to 12 billion tonnes could be economically stored if EOR technology 
continues to advance, and assuming that the cost of CO2 is 
less than $30-$38/ton delivered, which would require significant 
advances in carbon capture technology. To put this into context, total 
anthropogenic emissions of CO2 in the United States is 
around 6 billion tonnes per year, with around 2 billion tonnes per year 
of this CO2 from coal-fired power plants.
Conclusion
    CO2-EOR represents an early major opportunity for 
helping to realize carbon capture and sequestration technologies. The 
use of CO2-EOR projects could help power generation 
companies to take advantage of the oil industry's expertise with 
CO2 handling and injection, and help accelerate the 
implementation of other underground CO2 sequestration 
options in coalbeds, depleted oil/gas reservoirs, and deep saline 
formations. Developing the technology base needed to support a 
widespread expansion of CO2-EOR could substantially increase 
existing United States' oil reserves and production. The Department's 
development efforts are providing the elements needed to help enable 
this expansion by advancing capture technologies to increase the supply 
of CO2 and optimize EOR technologies for carbon 
sequestration co-benefits.
    Mr. Chairman, and members of the Subcommittee, this completes my 
statement. I would be happy to take any questions you may have.
                                 ______
                                 

   Response to questions submitted for the record by Scott M. Klara, 
    National Energy Technology Laboratory, U.S. Department of Energy

1.  Mr. Klara, last year the Department of Energy released a study on 
        America's Unconventional Fuels that recommended an aggressive 
        program for productively using industrial carbon dioxide 
        emissions for EOR. What would such a program entail, how does 
        it fit into the Department's existing carbon dioxide capture 
        program, and what would it cost?
    Response 1. The Department of Energy's (DOE) program for geologic 
storage of carbon dioxide focuses on saline formations because they 
have by far the largest capacity for carbon storage of any type of 
domestic geologic formation. While EOR represents a good low-hanging 
fruit for carbon sequestration, only saline formations have capacity on 
the scale that would be needed to sequester the carbon emissions from 
domestic coal power generation. Base EOR technology--using carbon 
dioxide to increase oil production--is commercially available and 
widely deployed, and the industry has both the financial incentives and 
resources to advance the technology on its own. The DOE program is 
focusing on EOR sequestration technologies where the private sector 
lacks incentive: monitoring, mitigation, and verification that will 
validate permanent CO2 storage in these applications, and 
best practices protocols for using EOR as a carbon storage option. 
While EOR-related CO2 research is not a specific line item 
within DOE's Sequestration Program, based on the 2009 President's 
Budget Request it is estimated that approximately $7 to $9 million will 
be provided for EOR-related activities within the Sequestration 
Program, primarily through field testing activities. In addition, many 
of the technologies DOE is developing for geologic carbon storage in 
saline and other non-EOR formations are also applicable to EOR. The 
2009 President's Budget Request provides $149 million for the 
Sequestration Program of which approximately $134 million is for 
geologic storage and $15 million is for capture R&D activities.
2.  Mr. Klara, what has the Department's budget for Enhanced Oil 
        Recovery research been for each of the past 5 years?
    Response 2.


    [GRAPHIC NOT AVAILABLE IN TIFF FORMAT]

    .eps*Includes broad-based Reservoir Efficiency Processes laboratory 
studies in addition to CO2-EOR field tests. In addition, 
many of the technologies DOE is developing for geologic carbon storage 
in saline and other non-EOR formations are also applicable to EOR.
3.  Mr. Klara, what type of research is the Department into, Enhanced 
        Gas Recovery or Enhanced Coal Bed Methane recovery?
    Response 3. DOE is currently pursuing unconventional gas technology 
research and development (R&D) with mandatory funds provided by the 
Energy Policy Act of 2005, Subtitle J, Section 999, which NETL manages 
and implements. The 2009 Budget proposes to repeal the mandatory oil 
and gas R&D program because the industry has the financial incentives 
and resources to develop new ways to extract oil and gas from the 
ground more cheaply and safely. Coalbed methane recovery is one small 
aspect of that program; however, nearly all current work in Section 999 
is related to technologies focused on enhancing recovery of natural gas 
from fractured shales.
4.  Mr. Klara, has the Department of Energy carried out the Enhanced 
        Oil Recovery demonstration program mandated by Section 354 of 
        the Energy Policy Act of 2005? Could you provide us with an 
        update on the progress of that program?
    Response 4. The DOE carbon sequestration program's EOR activities 
focus on EOR sequestration technologies where the private sector lacks 
incentive: monitoring, mitigation, and verification that will validate 
permanent CO2 storage in these applications, and best 
practices protocols for using EOR as a carbon storage option. 
Consistent with Section 354(c)(2)(B), the Department issued a 
solicitation on February 1, 2006, for Enhanced Oil Recovery (EOR) field 
tests. The solicitation closed on May 5, 2006. Project selection was 
made on July 21, 2006, and a news release announcing the selection was 
published on the National Energy Technology Laboratory's website on 
September 6, 2006. One award was made to the University of Alabama.
    Status of the project initiated under the program: Following the 
completion of a detailed reservoir characterization effort, the 
University of Alabama initiated studies to establish the feasibility of 
using carbon dioxide (CO2) for EOR in the heterogeneous 
Citronelle field in Alabama. That feasibility has been confirmed and 
pilot flood design efforts are almost concluded. Concurrently with the 
determination of feasibility, the University's industry partner, 
Denbury Resources, initiated field work to refurbish wellbores and 
facilities in preparation for a 5-spot pilot CO2 flood. The 
pilot design is scheduled for completion in July 2008 and will be 
submitted for NETL review prior to the initiation of field 
CO2-EOR pilot operations. The pilot is anticipated to start 
around November 2008. If the pilot is successful, Denbury Resources 
plans to extend their existing CO2 flooding operations near 
Jackson Dome, Mississippi, to the Citronelle Field.
5.  Mr. Klara, your testimony mentions injecting carbon dioxide into 
        fractured shale formations in North Dakota--do we know whether 
        or not those formations can effectively store carbon dioxide 
        without leaking?
    Response 5. The primary geologic storage options that are being 
considered for carbon sequestration are saline formations, oil/gas 
formations, and unmineable coal seams. Geologic storage capacity 
estimates generally include only these options. As research continues 
to unfold, several geologic storage options related to basalt 
formations and shale formations may emerge as potential storage 
candidates. These storage options are beginning to be investigated as 
potential options for safely and permanently storing carbon dioxide, 
and conclusive results verifying their effectiveness are still several 
years away.
                                 ______
                                 
    Mr. Costa. Thank you very much, Mr. Klara, for your 
testimony.
    Let me begin the questioning. The Department of Energy 
released a study, I guess, recently on America's unconventional 
fuels that recommend investigation of assessment of potential 
fiscal incentives to encourage the investment of CO2 
for EOR projects.
    Is the Department doing this since they released the 
report? And are there any results that you can speak of?
    Mr. Klara. Yes. The Department is still studying those 
efforts, and studying those issues. And several reports have 
been released, or are in preparation, relative to looking at 
the potential for CO2 EOR throughout the United 
States, and through numerous basins that are called geologic 
basins. And I would be happy to give you a status on those 
after the hearing.
    Mr. Costa. All right. Several times in your testimony you 
talked about various studies that were being done with Advanced 
Resources International. When do you expect those evaluations 
to be finished?
    Mr. Klara. We have several of those that are already 
developed and finished, and we would anticipate most of those 
being done over the course of the next, say, nine months to a 
year.
    Mr. Costa. And how about in the year of enhanced gas 
recovery, or the enhanced coalbed for methane recovery? Is 
there any research being done in those two areas?
    Mr. Klara. Yes. The majority of that research right now is 
being done in the carbon-capture and storage area, where we are 
looking at the use of carbon dioxide in coalbeds, for example, 
to enhance gas recovery of coalbed methane.
    Mr. Costa. And where is the Department of Energy in 
carrying out the enhanced oil recovery demonstration program 
that was mandated in the previous legislation that was noted, 
Section 354 Energy Policy Act of 2005?
    Mr. Klara. I would have to get back to you on that, sir.
    Mr. Costa. Please do.
    Mr. Spisak, does the BLM see carbon-dioxide enhancement oil 
recovery as a significant component of our future production 
for Federal lands? And if so, what percentage, or how would you 
describe its role in the future?
    Mr. Spisak. I think there is significant potential there. 
There are a number of depleted oilfields, or partially depleted 
oilfields on Federal lands, that might be candidates for carbon 
sequestration. But as was mentioned earlier, each case would 
need to be evaluated separately. And I think we are ready to 
assist in that.
    As you are aware----
    Mr. Costa. Has the Bureau of Land Management begun 
undertaking that assessment?
    Mr. Spisak. We primarily provide access to others to 
develop, and that is our expertise, if you will. We have 
regulations in place that we believe can deal with, dealing 
with rights-of-way for CO2 pipelines, and the 
planning side. But our regulations primarily allow us to 
authorize CO2 injection for enhanced oil recovery 
only.
    Mr. Costa. OK. But let me ask it to you in a different way, 
I guess, and that will be a subject, I guess, of the next 
panel. But has industry that has participated in these fields, 
have they come to you folks indicating that there is a stronger 
interest, given the current energy crisis that we are facing, 
and the cost of fuel, to pursue these older fields?
    Mr. Spisak. We are starting to see that, through our sundry 
notices, where companies will ask that a well be shut in for 
potential CO2 conversion at a later date.
    Mr. Costa. One of the concerns that has been raised, even 
though I believe this is kind of a win-win situation, that the 
carbon sequestration, that possibly the carbon dioxide might 
leak out of old well bores. Does the BLM, are they attempting 
to get a handle on this, on location and status of abandoned 
wells on public lands?
    Mr. Spisak. Well, part of Section 349 of the Energy Policy 
Act required us to inventory orphaned and idled wells, and 
prioritize those lists. And we have actually started that 
process. And so we have a better idea of the numbers of those 
types of wells that we have in our inventory.
    Mr. Costa. My final question to you, Mr. Spisak. In 2006 
the Department of Interior concluded that the royalty relief 
for oil produced from industrial carbon dioxide was not 
warranted. Why was that?
    Mr. Spisak. Well, we have existing regulations that allow 
us, on a case-by-case basis, to allow royalty reductions to 
help promote that type of activity. And we felt like we could 
always open up that issue in the future, if necessary.
    Mr. Costa. Are companies telling you that there are any 
complications under the existing mineral leasing laws and 
regulations that would create more difficulty if they convert 
to a current EOR project on Federal lands?
    Mr. Spisak. We haven't been hearing anything along those 
lines at this point.
    Mr. Costa. My time has expired, so I will now defer to the 
gentleman from New Mexico, Mr. Pearce.
    Mr. Pearce. Thank you, Mr. Chairman.
    Mr. Spisak, you heard the Chairman say that there are 
10,000 APDs that are not being utilized. I am looking at a 
chart that shows in 2001, we had protests filed on 17 percent 
of the parcels which are offered for development. That number 
has increased to 58 percent today, 81 percent in the Rocky 
Mountains alone.
    Do you find that, do you see that in real life, that we are 
actually finding protests, maybe three to four times higher? 
And would that be a reason that we are not producing in some 
areas?
    Mr. Spisak. Well, protests are typically at the lease-
issuance or offering stage. The number of APDs and the number 
that are actually acted upon need to take into consideration 
that APDs now, with the updated onshore order, there is two 
years' period of time for the companies to be able to use them, 
which could be extended to another two years. And a lot of it 
depends on various timing restrictions that are in place. And 
so that the companies have to work that into account, as well 
as rig availability, which is, with the big run-up, companies 
are scrambling to get rigs either built and crews to be able to 
utilize the APDs that are in the pipeline.
    Mr. Pearce. OK. You have a lot of----
    Mr. Costa. If the gentleman would yield, and I won't count 
it against you. But on the number I used, and I will be happy 
to double-check it, but those 28,000 application of permits to 
drill have been approved, so they are not under protest.
    Mr. Pearce. Thanks. Now, we were talking about the carbon 
sequestration and the use in the EOR, like the infrastructure 
already exists, Mr. Spisak. Is that accurate, that we would use 
the same infrastructure to move carbon dioxide?
    Let me hold up a map. I am visualizing the problem almost 
the same as our natural gas movements. In other words, we have 
to move carbon dioxide from where it was produced, somewhere.
    And so I am wondering that front chart there--yes, this 
chart here--I am wondering if we are going to see a system of 
pipelines like that to carry carbon dioxide to the fields, and 
then carry the enhanced oil back out.
    Mr. Spisak. As mentioned in my testimony, the issue of 
infrastructures such as pipelines, right now the pipeline 
network is to deliver natural gas away. And those aren't 
necessarily going to be the pipelines that could deliver 
CO2 to----
    Mr. Pearce. Right. So what kind of a permitting process are 
we talking about? If, I mean, we have to take carbon from 
everywhere in the country, take it in, gather it up, and then 
send it to some processing plant, and then back out to the 
oilfields? What sort of permitting problems do we face, just 
getting those pipelines to convey the CO2?
    Mr. Spisak. Well, as is anything when the level of activity 
is, as it increases, we have a certain workload, workforce that 
is able to process----
    Mr. Pearce. To get this done in the next 10 years. Could 
you get the permitting done with the current workload?
    Mr. Spisak. We are pretty full up as it stands now.
    Mr. Pearce. OK. So what I am saying is that it is not like 
they are available.
    Mr. Spisak. Correct.
    Mr. Pearce. Mr. Klara, I noted in page 4 of your testimony 
you talk about DOE as significantly advanced, enhanced oil 
recovery. Can you tell me the contributions that DOE has made 
on this?
    Mr. Klara. Yes. A few examples----
    Mr. Pearce. Just very brief, because we need to move on to 
another question.
    Mr. Klara. Yes. A few examples. For example, CO2 
bypasses a key issue that limits the effectiveness of 
CO2. And there has been a lot of research done, and 
additives to carbon dioxide.
    Mr. Pearce. Can you move the mic a little bit closer?
    Mr. Klara. There has been a lot of research done with 
additives to carbon dioxide and other additives in the 
reservoir to get a more effective flood-front of carbon 
dioxide.
    In addition, there has been a lot of work on things like 
reservoir management strategies and using new well techniques, 
like horizontal wells.
    Mr. Pearce. These are DOE-sponsored events, not companies 
that are using their own resources. These are DOE advancements?
    Mr. Klara. DOE certainly has been a part of many of those 
advancements.
    Mr. Pearce. That wasn't quite my question, but I will move 
on.
    You mention on page 2 that the global warming is 
significantly linked to carbons, CO2, methane, 
nitrous oxide, everything else in the environment. What is your 
professional opinion on why the polar icecap tripled in size 
this last winter? Why did we have the coldest winter on record 
in most of the northern hemisphere? Why did we have ice in 
Vietnam when I was there? In 1971, 1972, and 1973 I didn't find 
ice anywhere; and yet we had ice for almost 30 days in Vietnam.
    The carbon has decreased in our atmosphere. Exactly what is 
your professional opinion on this sudden reversal in our 
climate?
    Mr. Klara. Well, sir, I am not a climate-change expert, so 
I am going to----
    Mr. Pearce. OK. You put it in your testimony. So when you 
start using words that you can't--I mean, there are questions 
that are raised significant on this very point. So when you use 
statements like that in your testimony, it gives the appearance 
that you are experienced, and you can give data about that. And 
I think it is a very significant question. If you would get 
somebody in your agency to answer that question, I would 
appreciate that.
    Mr. Klara. OK, we will do that.
    Mr. Pearce. OK, thanks. I see my time has gone, Mr. 
Chairman. If we do two rounds, I have another series.
    Mr. Costa. All right. The gentleman from New Jersey is 
next, Mr. Holt.
    Mr. Holt. Thank you, Mr. Chairman. And thank you for 
setting up this hearing.
    Let me ask, what are the major areas of research? I am 
trying to get a sense of the scale of the investment that is 
necessary for research into all aspects of using public lands 
for sequestration of the carbon. You have to look at the 
leakage, how extensive is it to study that; you have to look at 
the feasibility of transportation of the carbon dioxide, and so 
forth.
    Has someone mapped out a long-term research, or short-term 
even, research plan? I suppose Mr. Klara would be the best 
person to start with, but I welcome comments from Mr. Spisak, 
also.
    Mr. Klara. We have a program within the Department of 
Energy, our Fossil Fuel Research Program, that is dedicated to 
developing the technologies to try to make that happen. And we 
have numerous goals and issues throughout our program over the 
course of up through 2020 and 2025, for example, that will 
hopefully set the stage for commercial availability of emerging 
technologies.
    Relative to enhanced oil recovery and using CO2, 
I think there are several key issues. First, you need mature 
fields, and the United States happens to have that happening 
automatically. Second, you need cheap sources of carbon 
dioxide. And relative to human activities and anthropogenic 
CO2, you need cheap sources of anthropogenic 
CO2. So a significant portion of the research 
program is looking at reducing the cost of CO2 
capture from energy facilities like power plants, looking at 
developing best practices and protocols for carbon storage and 
underground formations, to ensure it is permanent and safe. And 
those are some of the key aspects of the research program.
    Mr. Holt. And as this is mapped out, I mean, would it all 
be done by the Energy Technology Laboratory? Or is this, I am 
trying to get a sense of the scale of the investment that is 
necessary, public and private, to determine whether this is 
going to be a reality.
    Mr. Klara. In Fiscal Year 2008, the research budget for the 
coal program, for example, is in the neighborhood of $500 
million. And most of what we do in the coal program is 
dedicated toward future energy power-plant configurations to 
deal with the CO2 issue.
    And we believe that, I believe that sustained investment is 
required for us to----
    Mr. Holt. You are saying most of the $500 million goes into 
studying sequestration of the carbon?
    Mr. Klara. No, no, no. Don't----
    Mr. Holt. That is what I am asking about, for the 
sequestration of the carbon.
    Mr. Klara. Right. Our carbon sequestration program alone is 
in the neighborhood of $120 million for Fiscal Year 2008. And 
what I meant by the comment of linking it to the entire 
research program was that whether you are looking at 
gasification of fuel cells, advanced turbines, all of those 
development efforts have in mind future plants that have to do 
with the CO2 issue. So there is aspects within all 
of those program elements that are concerned about future 
configurations that deal with CO2 capture.
    Mr. Holt. Does BLM have a research program?
    Mr. Spisak. No, I wouldn't characterize what we do as 
research. It is more land management access, working through 
how they would implement such research on the ground.
    Mr. Holt. OK. Mr. Spisak, if there were more extensive use 
of carbon for enhanced oil recovery, what would be the 
environmental effects that you have identified, other than 
pipelines? To the extent that pipelines would have 
environmental effects.
    Mr. Spisak. Injecting the fluid into the ground, like other 
fluids, water is a fairly I would say routine matter when it 
comes to enhanced oil recovery with CO2 injection.
    CO2, when it does mix with water, can have some 
corrosive aspects. But I wouldn't expect that those types of 
environmental concerns are any more dangerous than the types of 
things we deal with every day.
    Mr. Holt. And quickly, Mr. Klara, if it can be answered 
quickly, how does one study leakage of carbon dioxide from coal 
seams or oil, depleted, or partially depleted oil areas? How do 
you study that, actually?
    Mr. Klara. The key there is to develop the suite of 
monitoring technologies that will allow you to look at the 
migration of carbon dioxide in the underground strata, at the 
surface, as well as even aerially. So there are some aerial 
technologies, plane flyover technologies, for example, that can 
look for leakage.
    So the key there is a whole portfolio of imaging 
technologies that is applied to a carbon storage location that 
will allow you to essentially look at nearly all of the carbon 
dioxide, and know where it is at given period of time.
    Mr. Costa. The gentleman's time has expired. Thank you.
    The gentlemen from Louisiana, Mr. Scalise.
    Mr. Scalise. Thank you, Mr. Chairman.
    Mr. Spisak, how often do companies file an application for 
a permit to drill, but never, in fact, develop that, or drill?
    Mr. Spisak. I don't have a specific answer, but to say, but 
we find that over a four- or five-year period, about 75 percent 
of the APDs that are filed are eventually drilled. This is 
based on a study of looking at APDs back in 2004/2005.
    Mr. Scalise. Over a five-year period roughly, then.
    Mr. Spisak. Right.
    Mr. Scalise. What would be a reason that someone would file 
the application, get the permit, but the not drill?
    Mr. Spisak. One example might be they might drill a well; 
they might find that the downhole was different than they were 
expecting, and some of the other APDs in the pipeline that they 
had approved may not be appropriate for that development.
    It could be that there is time constraints on seasonal 
restrictions for winter or deer cabin, or whatever it might be, 
closes the window down that they are able to drill the wells 
that they are needing, and so they have to push them off in 
time.
    Another may be that they have a certain amount of rig 
availability to deal with the APDs that they have, and they are 
not able to get enough rigs or rig crews in there to drill the 
APDs that they have.
    Mr. Scalise. I don't have any more questions. That is all I 
have.
    Mr. Costa. OK. All right. I am going to use the discretion 
of the Chair at this time. We have had one round of questions, 
and I will ask the Committee members to submit any written 
questions, if you have any additional questions, and move on to 
our second panel.
    Thank you very much, gentlemen, for your testimony and your 
prompt response on the answers. And as we are waiting for the 
other witnesses to come forward for the second panel, we will 
try to get through their testimony as best we can, hopefully 
before the votes are called, at which point we will have to 
recess and go to the Floor. And that will take about 40 
minutes. That will be a break for all of you here in the 
audience and all of you participating. And then we will come 
back and resume the hearing where we left off.
    So thank you, gentlemen. And I will take this time, as our 
second panel is coming forward. The lady that is standing up is 
Holly Wagenet. You can acknowledge, wave to everyone, Holly. 
This is her last hearing as a part of the Committee. She has 
applied to law school, and she is going to go there, and I 
suspect she will do well, as she does in every other effort. We 
want to thank you for all the nice work you have done on behalf 
of the Subcommittee. And Holly Wagenet is being replaced by the 
lady next to her, Marcie Cooperman. Raise your hand, Marcie. So 
we want to make sure she is part of our able staff, to do a 
good job. And we thank them for their hard work, and wish you 
the very best, Holly. Yes.
    [Applause.]
    Mr. Costa. She told me not to do that yesterday, so what 
can I say?
    Anyway, we have five witnesses here. And let us begin first 
with Mr. Tracy Evans, in our second panel. He is the Senior 
Vice President of the Reservoir Engineering with Denbury 
Resources, Inc. Mr. Evans.

 STATEMENT OF TRACY EVANS, SENIOR VICE PRESIDENT OF RESERVOIR 
              ENGINEERING, DENBURY RESOURCES, INC.

    Mr. Evans. Thank you, Chairman Costa, Ranking Member 
Pearce, and members of the Subcommittee for the opportunity to 
share our views on enhanced oil recovery utilizing carbon 
dioxide, or CO2 EOR.
    Denbury's primary focus is enhance oil recovery utilizing 
CO2, and we believe it can play an important role in 
meeting America's future energy needs, and helping to reduce 
greenhouse emissions.
    As Denbury's Senior Vice President, I oversee all reservoir 
engineering, land, property acquisitions, and purchases of 
anthropogenic or manmade CO2 volumes.
    We are currently the largest oil producer in the State of 
Mississippi, and one of the largest injectors of CO2 
in terms of volume in the United States. Since 1999, we have 
produced over 20 million barrels of oil from CO2 
flooding from 10 active EOR projects in Mississippi and 
Louisiana.
    Currently we utilize 550 million cubic feet, approximately 
32,000-plus tons, of new CO2 each day to produce 
about 24,000 gross barrels of oil per day. All this 
CO2 comes from a natural deposit that we currently 
own. Although large, this supply is enough that it could supply 
us with up to 800 million cubic feet of additional 
CO2, and the discussions to acquire additional 
volumes, as well.
    It is important to note that we plan to purchase this 
anthropogenic CO2. Thus, unlike the straw freely 
provided by the king in the tale by the Brothers Grimm, 
CO2 is not free; and in fact, its price typically 
varies proportionately with the price of oil.
    Also, unlike spinning straw into gold, CO2 
generally must be transported significant distances from 
natural or anthropogenic sources to oilfields, and injected to 
produce incremental volumes over 20 to 30 years.
    We currently operate three pipelines in operation, 
distributing CO2 from our natural source at 
Jacksonville, Mississippi, to our oilfields with a combined 
length of around 350 miles. Our biggest single project during 
2008 and 2009 will be the construction of a $750 million, 314-
mile, 24-inch pipeline to transport CO2 from 
southern Louisiana to southeast Texas. The primary purpose of 
this pipeline is to capture anthropogenic volumes of 
CO2.
    The potential construction of gasification plants with the 
numerous additions to deplete oilfields along this route make 
this region attractive to additional CO2 EOR. Thus, 
CO2 EOR is a long-term capital-intensive endeavor. 
Nonetheless, we believe it has enormous potential in the near 
term to help address the urgent, often conflicting goals of 
increased energy security and lower greenhouse gas emissions.
    At the present time, CO2 injections for the 
purposes of CO2 EOR total approximately 2 billion 
cubic feet per day; and generally in three regions of the 
country: West Texas, Mississippi, and Wyoming. All other oil-
producing regions of the country could and would benefit from 
CO2 EOR. Unfortunately, these areas do not have 
sufficient CO2 supplies.
    We estimate that if enough CO2 were available in 
all producing regions of the country, we could inject upwards 
of five to six times the current amount of CO2 being 
injected. To put this in perspective, this additional 
CO2 volume is equivalent to approximately 40 typical 
gasification projects that would produce around 200 million 
cubic feet per day per project. Thus, if such projects can get 
off the ground, the potential for additional oil production 
using CO2 EOR is significant.
    I will now briefly address two obstacles to increasing EOR 
production and carbon sequestration: The cost of capture and 
transportation, and the lack of clear tax rules applicable to 
pipelines carrying anthropogenic CO2.
    Perhaps the single-largest obstacle developing carbon-
capture, transportation, and sequestration beyond the limited 
number of projects currently in operation is the significant 
costs involved. The cost of capture stems from the variations 
in the quantity and the quality of CO2 produced by 
hydrocarbon combustion or gasification, or other industrial 
processes, as well as the cost of purchase and power of the 
compressors necessary to pressure up the gas sufficiently to 
enter a pipeline in order to get it to a sequestration site.
    Transportation costs are also significant. Insulation costs 
for CO2 pipelines have increased in recent years 
from about $30,000 per inch-mile for Denbury's free-state 
pipeline to an estimated $100,000 per inch-mile for the planned 
green pipeline in southern Louisiana, primarily due to rising 
steel prices, rising energy prices, and construction costs, 
effectively doubling our CO2 transportation rate. 
Without some means of reducing the cost of CCS infrastructure, 
development will likely remain stagnant.
    Certain committees and Members of Congress have already 
taken steps to address cost issues, and to remove obstacles to 
infrastructure development. For example, one year ago the 
Senate Finance Committee approved a clarification of the tax 
treatment of income from pipelines for transporting 
anthropogenic CO2.
    A substantial portion of CO2, natural gas, or 
products pipelines in the U.S. are owned and operated by 
publicly traded partnerships, whose reduced costs of capital 
lowers the costs of development and transportation of natural 
resources. However, due to the current uncertainty of the Tax 
Code, much of the existing CO2 pipeline capacity 
cannot be used, and new capacity may not get built to transport 
anthropogenic CO2 from emission sites.
    The Senate Finance Committee approved language to remove 
this uncertainty. This Congress ultimately failed to include it 
on the Energy Independence and Security Act.
    To conclude, the U.S. economy will continue to require 
massive amounts of energy well into the future. CO2 
can and should play an important role, helping to reduce 
dependence on imports. We can increase substantial volumes of 
domestic oil. And CO2 EOR is also the only currently 
active on-the-ground of CO2 injection and 
sequestration. And I look forward to answering any questions 
you may have.
    [The prepared statement of Mr. Evans follows:]

         Statement of Ronald T. Evans, Denbury Resources, Inc.

    Denbury Resources, Inc., (``Denbury'') appreciates this opportunity 
to share with Members of the House Subcommittee on Energy and Mineral 
Resources its experience with enhanced oil recovery using carbon 
dioxide or ``CO2 EOR.'' CO2 EOR presents 
significant opportunities to reduce the nation's dependence on foreign 
energy sources while simultaneously helping to reduce industrial 
emissions. With the right policies in place, many billions of barrels 
of oil are accessible on the Gulf Coast and around the United States 
and millions of tons of CO2 can be sequestered through 
CO2 EOR. However, some impediments exists--primarily tax and 
economic--to capturing and transporting CO2 on a broader 
scale in order to inject it and produce these significant volumes of 
domestic oil.
    As Senior Vice President, Reservoir Engineering, for Denbury, I 
oversee all reservoir engineering, land functions and acquisition 
activities; am responsible for securing and contracting sources of 
anthropogenic CO2; and coordinate our government relations. 
Denbury is currently the largest oil producer in the State of 
Mississippi and one of the largest injectors of carbon dioxide in terms 
of volume in the United States. Denbury's primary business focus is 
enhanced oil recovery utilizing CO2. At the present time we 
operate ten (10) active CO2 enhanced oil projects, nine in 
the State of Mississippi and one in the State of Louisiana.
    Denbury also owns the largest natural deposit of CO2 
east of the Mississippi River, called Jackson Dome in central 
Mississippi, which we extract and transport through approximately 350 
miles of dedicated CO2 pipelines for use in EOR. Denbury is 
currently in the process of designing or constructing an additional 375 
miles of CO2 pipelines in order to expand our operations 
into additional fields throughout the Gulf Coast of the United States. 
The Subcommittee may also be interested to know that Denbury is working 
with the federal Department of Energy and various research universities 
on several Phase II and Phase III demonstration projects in the 
Regional Carbon Sequestration Partnership Program. Finally, while our 
business model focuses primarily on the transportation and 
sequestration aspects of carbon capture and sequestration (``CCS''), we 
are also very familiar with the capture component both in terms of (1) 
the compression demands of transportation and sequestration and (2) our 
enhanced oil operations, which capture and recycle large volumes of 
CO2 in order to recover additional volumes of oil. Given 
this background, Denbury is pleased to share with you its expertise in 
CO2 EOR and its views on policy implications for the 
nation's energy security and efforts to reduce industrial emissions.
    A thorough understanding of both (1) the physical processes by 
which CO2 is obtained, transported and injected for purposes 
of EOR, and (2) the economics that underlie existing and future EOR-
related use of CO2 is essential to any consideration of 
potential policy issues. The costs associated with capturing and 
transporting CO2, whether in the context of EOR or 
otherwise, are significant and varying and--perhaps the single largest 
obstacle to developing carbon capture and transportation infrastructure 
beyond the limited, discrete projects currently in operation. From 
Denbury's perspective, it is critical that any contemplated state or 
federal legislation or regulation not increase these costs and impede 
private sector development of the infrastructure necessary to meet the 
demands of our energy hungry and potentially carbon-constrained world.
I. Capture / Compression
    The starting point for any CO2 EOR project is to produce 
or capture the CO2. Denbury currently obtains all of its 
CO2 from its natural deposit at Jackson Dome. Certain 
existing and some evolving technologies allow CO2 emitted 
from various manufacturing processes to be captured. The combustion or 
gasification of hydrocarbon-based fuels such as coal, petcoke or other 
hydrocarbons produces particularly large volumes of CO2 at 
varying levels of quality and purity. As new capture-inclusive projects 
are constructed, Denbury plans to acquire thousands of metric tons of 
CO2 each day for use in EOR.
    Aside from the threshold questions of how to properly classify 
CO2 and whether and to what extent to restrict emissions, 
from Denbury's perspective, the capture of CO2 presents no 
significant policy issues. Rather, the capture component presents a 
significant economic issue: First, existing capture technology is 
expensive. The byproduct of hydrocarbon combustion or gasification is a 
stream of gases and other impurities that contains various quantities 
of CO2. In order for CO2 to be usable in EOR it 
must be injected in a relatively pure form. Similarly, CO2 
injected into deep saline reservoirs must be in a relatively pure form 
to maximize the storage space available to be filled with 
CO2. Thus, a significant component of the capture cost is 
the cost to separate and purify the CO2 to be injected. The 
lower the percentage of CO2 in the stream of gases, and the 
greater the amount of impurities in the stream, the greater the cost of 
capture. Second, most technologies capture the CO2 at a 
lower pressure than is required to either enter a typical 
CO2 pipeline or to inject into a deep saline reservoir or 
EOR project. The costs of the compressors and the power necessary to 
drive them are significant--approximately $7.50/ton of the estimated 
$20/ton total cost 1 for CO2 that is transported 
moderate distances. Therefore, the compression costs associated with 
CO2 capture are slightly more than one-third (33%) of the 
total CCS cost for the least expensive sources of anthropogenic (man-
made) CO2. Additional compression costs are incurred to 
maintain pressure in pipelines and again when CO2 is 
pressured up to a sufficient level for EOR reservoir injection. In 
summary, without some means of reducing the cost of captured 
anthropogenic CO2 significantly, infrastructure development 
will likely remain stagnant.
---------------------------------------------------------------------------
    \1\ Total costs of CCS varies substantially by source of 
CO2--to upwards of $70/ton--and even across proposed 
gasification projects because of variances in each process. This figure 
represents an estimate of the lowest-cost industrial-sourced 
CO2.
---------------------------------------------------------------------------
    To address this issue, last year the Finance Committee approved a 
tax credit for the capture and sequestration of CO2 of 
$10.00/ton in connection with EOR and $20/ton for non-EOR projects for 
up to 75,000,000 tons sequestered. From Denbury's perspective, this 
would be sufficient to incentivize construction of additional pipelines 
from emission sites to geologic sequestration sites in connection with 
EOR activities. Unfortunately, this provision was not included in the 
energy legislation ultimately signed into law in December. We hope that 
Congress will address the issue of CCS costs in 2008, especially those 
associated with capture and compression, and note that proposed 
projects from gasification through to sequestration have the potential 
to create hundreds and perhaps thousands of jobs across the country.
II. Transportation
    The most economical way to transport CO2 is through 
pipelines at pressures in excess of 1100 psi so that the CO2 
is transported as a supercritical fluid (dense phase). At pressures in 
excess of 1100 psi and temperatures common for CO2 
pipelines, CO2 is a supercritical fluid which means that the 
CO2 has properties of both a liquid and a gas. Larger 
volumes of CO2 can be transported through CO2 
pipelines in this dense phase than can be transported as a gas. Given 
the pressure requirements to maintain CO2 in the dense 
phase, CO2 pipelines are generally operated at pressures 
greater than 2,000 psi. This pressure is well in excess of the average 
operating pressure of a natural gas pipeline, though the material used 
to manufacture both types is the same.
    At the present time there exist over 3,500 miles of dedicated 
CO2 pipelines, most of which have been transporting 
CO2 for over 20 years--and some for over 30 years. (see 
Attachment No. 1) However, this is just a fraction of the pipeline 
network that exists for oil and natural gas and covers very limited 
geographic areas. The vast majority of CO2 pipelines 
transport natural CO2 from natural underground 
CO2 production sources that are owned and operated by the 
CO2 pipeline owner--generally for use in enhanced recovery 
projects also owned and operated by the CO2 pipeline owner. 
In cases where the owner of the CO2 pipeline has 
CO2 production volumes in excess of its own EOR 
requirements, the excess CO2 volumes are sold to EOR 
operators in other projects or to industrial gas suppliers. This 
limited number of regional CO2 shippers and consumers stands 
in marked contrast to the numerous and geographically widespread 
producers and consumers of oil and natural gas products. As with the 
development of the extensive network of natural gas, oil and 
hydrocarbon products pipelines, CO2 pipelines should also be 
given room to grow by state and federal regulatory authorities
    The construction and installation of CO2 pipelines is a 
capital intensive effort, the costs of which have increased in recent 
years for a variety of reasons, including rising steel prices, 
construction costs and energy prices. By way of example, Denbury's 93 
mile, 20 inch Freestate pipeline (see Attachment No. 2) completed in 
2006 cost approximately $30,000 per inch-mile, resulting in an 
effective transportation rate of approximately $3.50/ton at full 
capacity. The initial 37 mile segment of Denbury's 24 inch Delta 
pipeline was completed in 2007 at a cost of approximately $55,000 per 
inch-mile. We estimate that our planned 314 mile, 24 inch Green 
Pipeline that will run from Donaldsonville, Louisiana to Hastings field 
in southeast Texas will cost approximately, $100,000 per inch-mile 
resulting in an effective transportation rate of approximately $7/ton 
at full capacity. While the length (pumping stations to maintain 
adequate pressure add an additional $1 to $2 per ton to transportation 
costs), route obstacles and type of terrain all added to the estimated 
cost of the Green pipeline, the fact remains that such endeavors, even 
under the best of circumstances are extremely costly and take years of 
careful planning.
III. Taxation
    Today, a substantial portion of all CO2, natural gas, 
oil and products pipelines in the U.S. are owned and operated by 
companies that are organized as Publicly Traded Partnerships commonly 
referred to as Master Limited Partnerships (``MLPs''), which through 
their lower cost of capital have been an important financing source for 
building these assets. Section 7704 of the tax code permits MLPs to be 
taxed so that income and tax liabilities are passed through to the 
partners, even though the MLPs are large public entities, provided 90 
percent or more of the MLP's gross income is derived from certain 
qualifying activities. These activities include exploration, 
development, processing and transportation of natural resources, 
including pipelines transporting gas, oil, or products thereof (see 
Sec. 7704(d)(1)(E)). While this provision covers the processing and 
pipelining of ``natural'' CO2, it is unclear whether it 
covers anthropogenic CO2. Because of this uncertainty, much 
of the existing CO2 pipeline capacity (that owned by MLPs) 
cannot currently be used to transport anthropogenic CO2 from 
emissions sites--at least not without significantly higher tax costs 
than other pipeline assets in the industry.
    Last year, as part of its energy tax package, the Senate Finance 
Committee adopted a modification to include industrial source 
CO2 in the definition of qualifying income (see Sec. 817 of 
the Energy Enhancement and Investment Act of 2007, June 19, 2007). 
However, Congress ultimately failed to include that package of 
provisions in the Energy Independence and Security Act of 2007 (P.L. 
110-140). Without this modification of the tax code, a substantial 
portion of the pipeline industry will most likely not contribute 
capital to the construction of the CO2 pipeline 
infrastructure necessary to facilitate CCS through transportation of 
anthropogenic CO2. We strongly urge Members of the Energy 
and Mineral Resources Subcommittee to work with their colleagues on the 
Ways and Means Committee and their counterparts in the Senate to 
accomplish this important clarification.
IV. CO2 EOR--Injection / Sequestration
    Approximately half of the oil that has ever been discovered will 
remain in the reservoir following primary and secondary production 
operations. In the proper environment, enhanced oil recovery utilizing 
CO2 has the ability to recover up to an additional 25% of 
the original oil in place or half of the remaining oil in place 
following primary and secondary operations. Enhanced oil recovery 
utilizing CO2 requires multiple injection wells throughout a 
unitized field or reservoir. CO2 injection wells are 
permitted and approved by each State's division or department of 
Underground Injection Control utilizing the standards and policies 
issued by the EPA. CO2 injection wells utilized in tertiary 
oil recovery (a.k.a. EOR) are permitted and approved as Class II 
Injection wells. Such wells have been in existence for over 30 years. 
We believe existing laws and regulations provide sufficient protection 
of the fresh water and ground water reservoirs from the injection of 
CO2 in EOR operations or, for that matter, in deep saline 
reservoirs.
    At the present time, CO2 injections for the purposes of 
CO2 EOR total approximately 2 billion cubic feet per day 
(Bcf/d) in three regions of the country, West Texas, Mississippi and 
Wyoming. Several other oil producing regions of the country could and 
would benefit from CO2 EOR. Unfortunately, these other areas 
do not have naturally occurring CO2 supplies. We estimate 
that if naturally occurring CO2 were available in all oil 
producing regions in the country, CO2 EOR could inject 
upwards of five or six times the current amount of CO2 being 
injected. To put this in perspective, this additional CO2 
volume is equivalent to approximately 40 typical gasification projects 
(200 MMcf/d per project).
    The amount of CO2 injected in CO2 EOR 
projects varies by oil producing area and project design. Although each 
project is different, the range of CO2 injected to produce a 
barrel of oil is four to twelve thousand cubic feet (Mcf). In order to 
produce oil through CO2 EOR, the injected CO2 
must physically contact the oil remaining in the reservoir. Oil 
remaining in the reservoir after secondary recovery operations cannot 
be recovered or produced unless the oil is physically altered. 
CO2 dissolves into the oil causing the oil to swell, the 
viscosity to reduce and the surface tension (force holding the oil to 
the rock) to reduce, allowing the oil to become mobile. Due to 
reservoir heterogeneities and existing well spacing some oil is not 
contacted and thus these characteristics of each CO2 EOR 
project are the limiting factor to recovering a greater percentage of 
the remaining oil. Further, CO2 EOR, while applicable to a 
fairly wide range of reservoirs and oil gravities, is not applicable to 
all. Generally, in order to keep the CO2 in the dense phase, 
a reservoir pressure in excess of 1,100 psi must be achieved, thus 
CO2 EOR is generally conducted in reservoirs below 3,000 
feet. In our opinion, CO2 EOR is the most efficient tertiary 
recovery technology available today for reservoirs in which 
CO2 EOR is applicable.
    At the present time Denbury is injecting approximately 550 million 
cubic feet per day (MMcf/d) of CO2 into its current 
CO2 EOR projects and is planning on initiating injections 
into three additional CO2 EOR projects in the near future 
which will increase our total injections to approximately 800 MMcf/d. 
Denbury has allocated essentially 100% of its proven CO2 
reserves to current and future projects that we own or have the option 
to purchase. Therefore we have been negotiating and contracting for 
anthropogenic volumes of CO2 from proposed gasification 
projects and other existing anthropogenic CO2 sources. We 
have signed three CO2 purchase contracts to date totaling 
almost 800 MMcf/d of anthropogenic CO2. These contracted 
volumes of anthropogenic CO2, and others in negotiation, are 
necessary for Denbury to expand its CO2 EOR operations to 
additional fields. These contracts also contain CO2 pricing 
provisions that are tied to the price of oil, so as oil prices 
increase, the price paid for the anthropogenic CO2 
increases. These contracted CO2 prices may or may not be 
sufficient to cover the CO2 capture and compression costs 
depending on several variables including (existing and future) capture 
and compression costs, the price of oil, the CO2 source, and 
the distance from the source to the CO2 EOR project.
V. Conclusion
    The U.S. economy will continue to require massive amounts of energy 
well into the future. We believe the country needs to use all of its 
resources to meet this demand. Given current environmental conditions, 
there is also a desire to sequester significant volumes of 
CO2 from industrial sources. CO2 EOR's ability to 
address both of these realities make it uniquely well-suited to play an 
important role in America's energy and environmental future. For this 
to happen, the federal government should help address the significant 
costs of capturing and transporting CO2 as discussed above. 
The most important step Congress can take at present is to amend 
Section 7704(d)(1)(E) of the tax code to make clear that transportation 
of anthropogenic CO2 is included. This will allow a 
significant number of industry participants to lead the way in 
developing the infrastructure necessary for a carbon constrained, 
energy dependent world. By providing necessary mechanisms to foster 
CO2 EOR (whether on federal or privately owned land), and 
allowing states to continue to oversee its development, the U.S. can 
realize significant increases in domestic oil production and benefit 
from reduced industrial emissions.
    Just as we believe the country needs to draw upon all of its vast 
resources to meet our energy requirements, we recognize that many 
different avenues must be explored and researched to exponentially 
reduce emissions. The EOR industry's experience with using 
CO2 and its knowledge of oil reservoir geology should 
greatly facilitate the commencement of significant CO2 
sequestration today versus some distant time in the future. The 
substantial body of knowledge and expertise with CO2 EOR 
that exists is why we believe it will be the primary method of 
sequestering CO2 in the near term, while research is 
completed on additional technologies and geological formations. 
CO2 EOR is not the sole answer to America's energy or 
environmental challenges. However, it can be a key part of solving this 
complex puzzle.
Attachment No. 1

    [GRAPHIC NOT AVAILABLE IN TIFF FORMAT]


Attachment No. 2

    [GRAPHIC NOT AVAILABLE IN TIFF FORMAT]

    Response to questions submitted for the record by Tracy Evans, 
 Senior Vice President of Reservoir Engineering, Denbury Resources Inc.

Questions & Responses
1.  Mr. Evans, if the government enacted that fix to the pipeline tax 
        code that you mention, how much investment do you think that 
        would bring in from the private sector?
    It is difficult to quantify with any certainty how much private 
sector investment would result from clarification of Section 7704 of 
the tax code with respect to anthropogenic carbon dioxide 
(CO2). Denbury's expertise lies in tertiary oil recovery 
methods, and pipeline construction investment decisions depend on 
multiple factors in addition to tax policy. Nonetheless, such 
clarification would remove what is essentially a significant regulatory 
hurdle or disincentive to transporting man-made CO2 volumes 
from emissions sites to enhanced oil recovery or saline injection sites 
via dedicated pipelines, the most efficient mode of transporting 
CO2. Insofar as a major portion of oil, natural gas and 
CO2 pipelines are owned and operated by publicly traded 
limited partnerships, Denbury Resources believes that removing this 
obstacle would have a substantial impact:
      Our review of the Oil and Gas Journal's 2007 Pipeline 
Construction Report (published by Penwell) indicates that 10,500 miles 
of pipeline projects were proposed or planned (primarily to transport 
oil and natural gas products) as of its publication in November 2007. 
Of that amount, 78% or 8,100+ miles are being proposed or planned by 
publicly traded partnerships.
      Our review of the Pipeline Journal's most recent annual 
ranking of the top pipeline owners and operators in the United States, 
indicates that publicly traded partnerships account for 66%+ of the top 
20 liquid pipelines operators ranked by number of miles operated. 
(November 2007; data based on 2006 miles; Oildom Publishing Co.) These 
top 20 owners based on miles of liquid pipelines operated account for 
66%+ of the total number, (91,120 miles of 138,037 miles), of liquid 
pipelines in the U.S. If so-called legacy pipelines owned by major oil 
and gas companies are removed, the percentage owned and operated by 
publicly traded partnerships increases to 96%+.
      Looking at the top 20 gas pipeline operators, which 
account for approximately 75% of all gas pipelines (234,275 miles of 
312,586 miles) in the U.S., the percentage owned and operated by 
publicly traded partnerships is 43%+.
    From the above, it is very evident that publicly traded 
partnerships own or operate a substantial portion of pipelines 
operating in the U.S. today and are constructing or planning to 
construct the vast majority of new pipelines. It is hard to envision 
how the enormous pipeline network required to effectively transport 
CO2 for storage--via enhanced oil recovery, injection into 
saline aquifers, or otherwise--could be built without the resources, 
expertise and full participation of publicly traded partnerships. Such 
companies can hardly be expected to undertake the substantial effort 
and investment required to build CO2 pipelines while 
uncertain of the tax treatment of any eventual income derived from the 
transportation of anthropogenic CO2. CO2 pipeline 
owner/operator Kinder Morgan has also called attention to this issue. 
(See testimony of Vice President Charles E. Fox before the Senate 
Commerce Committee's Subcommittee on Science, Technology, and 
Innovation, November 7, 2007.)
    Further, due to their tax structure which results in lower costs of 
capital, publicly traded partnerships have historically been willing to 
accept lower rates of return on investment than public companies that 
are corporate entities. Thus, if publicly traded partnerships 
participate in the construction and ownership of CO2 
pipelines, the total cost of capturing, transporting and sequestering 
man-made CO2 will be lower than would otherwise be the case. 
If Congress is determined to increase domestic production through 
CO2 enhanced oil recovery (EOR) and to store CO2 
to reduce emissions, it should encourage the involvement of this key 
segment of the private sector by removing this uncertainty.
2.  Mr. Evans, what federal and state EOR incentives is your company 
        currently taking advantage of?
    Section 43 of the Internal Revenue Code provides a 15% tax credit 
for capital investments made in CO2 EOR projects. However, 
the credit is indexed to crude oil prices, which are now well above the 
maximum level at which the tax credit applies. Thus, Denbury utilizes 
some Section 43 EOR tax credits earned in prior years when crude oil 
prices were lower to offset federal taxes in the current year, but new 
Section 43 credits are no longer available
    At the present time, Mississippi, Louisiana and Texas (areas where 
Denbury operates) all provide for reduced severance taxes on oil 
produced as a result of enhanced oil recovery utilizing CO2. 
While each state varies in the amount of severance taxes levied, 
Mississippi and Texas each grant a 50% reduction in the amount of 
severance taxes paid on oil produced through CO2 EOR. 
Louisiana is different in that it grants a severance tax holiday (0%) 
until project payout is reached. In January 2008, Texas enacted a new 
regulation that grants an additional 50% (total of 75%) severance tax 
reduction for oil produced using man-made CO2 in EOR 
applications.
3.  Mr. Evans, your testimony mentions the tax credit for 
        CO2-EOR that was almost enacted last year and says 
        it would be enough to incentivize pipeline construction--would 
        it also be enough to incentivize capture as well?
    The tax credit approved by the Senate Finance Committee last year 
was for carbon capture and sequestration (CCS), not for CO2 
EOR. The point of the credit is not to subsidize pipeline construction, 
but to defray the high costs noted in my testimony of separating, 
capturing and pressurizing anthropogenic CO2. If capture 
costs--the most significant factor in total CCS costs--can be 
sufficiently reduced, the existing CO2 pipeline backbone 
could be significantly expanded in connection with EOR activities in a 
cost-effective manner. At current market prices for crude oil, a tax 
credit for the capture and sequestration of CO2 of 
approximately $10.00 per ton would lower total CCS costs sufficiently 
to encourage the capture of significant volumes of CO2 from 
the lowest cost emissions sources (i.e. +/-$20/ton for ammonia and coal 
gasification.). A reliable supply of man-made CO2 at a 
reasonable price, in turn, would encourage EOR end users to undertake 
the substantial investment required for construction of additional 
pipelines from emission sites to geologic sequestration sites. Thus, 
credits incentivizing capture would help create and match the 
CO2 supply with EOR demand, from which the pipelines to link 
the two would follow. These pipelines could ultimately be used to 
transport and sequester additional volumes of CO2 after the 
cessation of EOR operations.
    As I testified at the hearing, Denbury builds and owns pipelines to 
transport CO2 for use in its EOR operations. Denbury does 
not capture CO2 from industrial sources, although it has 
entered into agreements to purchase CO2 from projects that 
plan to capture it. So far, these projects--and many others that 
envision capturing CO2 emissions--have not started 
construction. The proposed tax credit could help advance many of these 
projects, namely those with the lowest estimated costs of capture, by 
addressing a major cost component. A larger credit may help advance 
additional projects--those with slightly higher capture costs.
    Senators Kent Conrad and Orrin Hatch recently introduced 
legislation (S. 3208) that contains a new version of the tax credit. 
The credit as structured in this bill would range from $15-$30 per ton 
of CO2 captured and sequestered and would be effective for 
ten years. Denbury supports these modifications and urges members of 
the Subcommittee to work with their colleagues to pass companion 
legislation in the House of Representatives.
4.  Mr. Evans, what sort of production levels do you think we could see 
        from CO2-EOR over the next 10 or 20 years? Could we 
        reach 1 million barrels per day? What would it take to make 
        those sort of production levels a reality?
    Assuming access to sufficient supplies of CO2 at 
reasonable prices in all oil producing regions of the country, I 
believe the United States could eventually reach production from 
CO2 EOR of up to 2 million barrels per day. It is difficult 
to estimate a time frame since that depends on many variables (rates of 
construction, labor costs, materials costs, etc.), but +/-20 years is 
reasonable. I arrive at this estimate as follows:
    The maximum rate of oil production the United States can expect 
from CO2 EOR depends on many factors, primarily the 
availability of CO2 at reasonable costs. CO2 EOR 
is applicable to all oil producing regions of the country but not to 
all oil producing reservoirs in each region. As discussed at the 
hearing, the success of CO2 EOR in a given reservoir depends 
on multiple factors such as reservoir depth, gravity of the oil, purity 
of CO2 stream, reservoir temperature, reservoir pressure, 
reservoir heterogeneity and other factors.
    Denbury has successfully utilized CO2 EOR in one oil 
producing region of the country with the only known naturally occurring 
significant source of CO2 east of the Mississippi River. 
When comparing our CO2 EOR volumes (an estimated 24,000 
gross barrels of oil per day) to the current daily total volume of oil 
production in the State of Mississippi (based on U.S. Energy 
Information Administration estimates for January 2008), CO2 
EOR is in excess of 42% of Mississippi's total production. With 
Denbury's future additional projects, CO2 EOR will 
eventually exceed 50% of total production in Mississippi.
    The Permian Basin of West Texas has the greatest number of existing 
CO2 EOR projects--more than any other oil producing basin in 
the country. It is estimated that total current oil production from 
CO2 EOR projects there is approximately 200,000 gross 
barrels per day while total daily production from all forms of oil 
production in the basin is approximately 678,000 barrels per day 
according to IHS, Inc., which maintains an industry production 
database. Thus, approximately 30% of the oil production from the 
Permian Basin is being produced through CO2 EOR.
    Applying the overall level of success with CO2 EOR in 
these two regions--30% to 50% of total production--to current U.S. oil 
production, which averages approximately 5 million barrels per day (a 
reasonable, useful analogy based on what we know of other oil-producing 
regions), would yield 1.5 million to 2.5 million barrels per day. Since 
it is unlikely that man-made CO2 will be delivered to all 
producing oil basins at the same time, I believe it's appropriate to 
reduce these figures by 20%. Thus, my estimate of potential additional 
oil production from CO2 EOR is 1.2 million to 2.0 million 
barrels per day.
    As stated at the outset, this estimate assumes access to sufficient 
supplies of CO2 at reasonable prices in all oil producing 
regions of the country. Reliable access to such supplies is what would 
it take to make these sort of production levels a reality. My answers 
to questions 1 and 3 above describe policies that, if adopted by 
Congress, would facilitate this.
                                 ______
                                 
    Mr. Costa. Thank you very much, Mr. Evans.
    Our next witness is Mr. William Roby, Vice President of 
Worldwide Engineering and Technical Services for Occidental Oil 
and Gas Companies.
    Mr. Roby, please.

     STATEMENT OF WILLIAM ROBY, VICE PRESIDENT, WORLDWIDE 
  ENGINEERING AND TECHNICAL SERVICES, OCCIDENTAL OIL AND GAS 
                          CORPORATION

    Mr. Roby. Thank you, Chairman Costa.
    Mr. Costa. The five-minute rule applies to all of you, just 
like the previous panel.
    Mr. Roby. Thank you. Thank you, Chairman Costa, members of 
the Energy and Mineral Resources Subcommittee, and other 
guests.
    My name is William Roby. I am Vice President of Worldwide 
Engineering and Technical Services for Occidental Oil and Gas 
Corporation.
    I greatly appreciate the opportunity to speak today 
regarding both Occidental's use of carbon dioxide to enhance 
the recovery of oil and associated gas in the United States, 
and some of the emerging policy issues related to enhanced oil 
recovery.
    These issues are of great importance to the nation, 
particularly as demand grows, and we seek ways to increase 
domestic production of oil and natural gas in this country, 
while reducing the concentration of CO2 in the 
atmosphere.
    By way of background, Occidental Oil and Gas Corporation is 
a Los Angeles-based oil and gas exploration and production 
company, with operations in the United States, the Middle East, 
North Africa, and Latin America. Sixty-three percent of 
Occidental's 2007 production occurred in the United States, and 
75 percent of our proven reserves are located in the United 
States.
    Enhanced oil recovery techniques have substantial economic 
and environmental benefits, and can significantly increase oil 
recovery. As a result, oil that would have been left in place 
is producible, and contributes directly to our domestic supply. 
Its use is being good stewards of our country's precious energy 
resources.
    In addition, CO2 EOR is a viable method for 
reducing greenhouse gases by reusing and storing CO2 
underground from industrial and power-generation facilities.
    CO2 has been used for over 30 years in the 
Permian Basin in West Texas, and New Mexico to enhance oil 
recovery. Since that time, Occidental has become the largest 
user of CO2 injection for EOR in the world. And 
CO2 flooding is our most commonly used EOR 
technique.
    Through CO2 flooding, the fields Occidental 
operates in the Permian Basin will produce over 1 billion 
barrels of oil more than would have been produced without this 
technology. Our experience shows that CO2 flooding 
has increased the ultimate oil recovery by an average of nearly 
25 percent.
    We now operate over 8,700 wells in 28 CO2 EOR 
projects in Texas and New Mexico. We have nearly 3,700 
CO2 injection wells that support 5,000 producing 
wells, and we inject approximately 1.4 billion cubic feet of 
CO2 each day, or 500 billion cubic feet per year, in 
the Permian Basin alone.
    However, using CO2 to enhance oil recovery is 
technically challenging and costly. Some oil formations are not 
amenable to CO2 injection, and all depend on 
geologic structure, permeability, and homogeneity of the 
formation. Additionally, oil production response sometimes 
takes many months to occur. We estimate that using 
CO2 to enhance oil recovery increases the cost per 
barrel of oil by more than 50 percent over typical secondary 
recovery operations.
    Notwithstanding the cost, we believe using CO2 
to increase oil recovery is an extremely important technology 
for meeting our national energy needs, and Occidental 
encouraged Congress to develop policies and incentives to 
increase its use. National policies and incentives to promote 
CO2 injections could significantly increase proven 
oil reserves. Increasing domestic reserves has additional 
benefits, including extending the life of aging reservoirs, 
increasing tax and royalty revenues for the public, increasing 
employment opportunities to operate the fields, and providing 
greater domestic supplies of energy.
    The committee specifically asked for suggestions on how to 
foster further use, and remove impediments to the expansion of 
CO2 enhanced oil technology. Since CO2 
EOR is a costly business proposition, these projects require 
robust, long-term economics to incentivize producers to 
undertake the risks. We have the following suggestions.
    Number one, investment incentives. We suggest you consider 
providing incentives such as investment credits, and 
accelerating depreciation of the project's capital cost, 
including infrastructure required to transport and inject 
CO2.
    Number two, royalty rates. We suggest that the government 
consider providing declining royalty rates on Federal leases 
where CO2 EOR is used.
    Number three, legal issues. Legal areas that warrant 
clarification include, one, confirming subsurface pore space as 
part of the mineral state; number two, predictable and defined 
rights and obligations relating to subsurface pore space 
ownership; and number three, the ability and easy modification 
of historic field unit agreements to accommodate EOR 
operations, including potential unitization raised by 
sequestration of CO2.
    And last, clear expectations regarding the disposition of 
EOR wells and fields, including oilfield CO2 
sequestration sites.
    However, we believe the current regulatory provisions and 
Permian regimes for conventional CO2 EOR operations 
work very well, and provide thorough oversight by the 
regulators and opportunity for public input.
    And I want to discuss the role CO2 EOR 
technology can play on controlling greenhouse gas emissions. In 
particular, one of the benefits of injecting CO2 for 
enhanced oil recovery is the ability to store significant 
volumes of CO2 in the reservoir, both during and 
after oil and gas production. In typical EOR operation, 
approximately one-third to one-half of the CO2 
initially injected becomes trapped in the reservoir. The rest 
is recycled from producing wells as a valuable commodity, and 
reinjected.
    As I mentioned earlier, Occidental currently injects 
approximately 500 billion cubic feet of CO2 per 
year. To put this in context, each year the amount of 
CO2 that Occidental injects is equivalent to the 
emissions of 10 150-megawatt coal-fired power plants.
    We have 30 years of history using naturally occurring 
CO2 from underground reservoirs. However, we just as 
easily could use CO2 captured from emissions of 
electrical utilities, refineries, and other large sources if it 
were available at competitive prices.
    We believe the key challenge to using manmade 
CO2 and EOR operations are the costs to capture 
carbon dioxide from industrial-power generation sources, and 
the cost of building the infrastructure to transport the 
CO2 to a field, and to compress it to the required 
pressure for injection into the reservoir.
    Occidental believes that industrial CO2 for 
natural recovery provides technical information, and 
demonstrates results for long-term CO2 
sequestration. In fact, this technology is a great way, is a 
gateway to future large-scale carbon sequestration; and the 
industry's 30-year history of using CO2 provides the 
evidence it can be managed safely.
    Mr. Costa. Mr. Roby, we appreciate your testimony, and you 
have done a good job.
    Mr. Roby. Yes, that is my last comment. Thank you very 
much.
    Mr. Costa. Thank you.
    [The prepared statement of Mr. Roby follows:]

Statement of William Roby, Vice President of Worldwide Engineering and 
         Technical Services, Occidental Oil and Gas Corporation

    Chairman Costa, members of the Energy and Mineral Resources 
Subcommittee and other guests, my name is William Roby. I am Vice 
President of Worldwide Engineering and Technical Services of Occidental 
Oil and Gas Corporation. I greatly appreciate the opportunity to speak 
today regarding both Occidental's use of carbon dioxide to enhance the 
recovery of oil and associated gas in the United States and some of the 
emerging policy issues related to enhanced oil recovery. These issues 
are of great importance to the Nation, particularly as demand grows and 
we seek ways to increase domestic production of oil and natural gas in 
this country while reducing the concentration of carbon dioxide in the 
atmosphere.
    By way of background, Occidental Oil and Gas Corporation is a Los 
Angeles-based oil and gas exploration and production company with 
operations in the United States, the Middle East, North Africa and 
Latin America. Sixty-three percent of Occidental's 2007 production 
occurred in the United States, primarily in the states of California, 
Texas, New Mexico, and Kansas. Seventy-five percent of our proven 
reserves are located in the United States.
    Before I discuss Occidental's experience with enhanced oil recovery 
using carbon dioxide or CO2, I want to briefly explain what 
I mean when I use the term ``enhanced oil recovery.'' Enhanced oil 
recovery, or EOR, is a generic term for techniques that increase the 
amount of oil extracted from a reservoir beyond primary and secondary 
recovery methods. Primary recovery refers to production where the 
hydrocarbons in the reservoir flow into the well due to the natural 
pressure in the reservoir. Secondary recovery refers to production 
where the hydrocarbons flow into the well because pressure in the 
reservoir is increased by injecting fluids, such as water or 
hydrocarbon gas, typically already found in the reservoir. Lastly, 
enhanced oil recovery refers to production from injecting materials not 
normally found in the reservoir such as steam, CO2 in large 
quantities, or other chemicals. These techniques are designed to 
increase reservoir pressure, reduce the oil's viscosity or alter oil's 
properties that cause it to be trapped in small pore spaces in the 
rock, thus improving oil's ability to flow through the reservoir and 
improve extraction.
    Enhanced oil recovery techniques have substantial economic and 
environmental benefits. They can increase production from an oil 
reservoir by an additional 10% to 50% of the oil originally contained 
in the reservoir. As a result, oil that traditionally would have been 
left in place contributes directly to our domestic supply. Recovering 
more oil from existing fields with EOR uses far fewer resources than 
simply abandoning older fields and installing new infrastructure, such 
as roads, pipelines and equipment, for primary production in new 
locations. In addition to these benefits from all EOR techniques, EOR 
using carbon dioxide flooding is a commercially viable method for 
reducing greenhouse gas emissions by reusing and storing CO2 
underground that would otherwise be emitted from industrial or power 
generation facilities to the atmosphere.
    Carbon dioxide has been used for over thirty years in the Permian 
Basin in West Texas and New Mexico to enhance oil recovery. Since that 
time, Occidental has become the largest user of CO2 
injection for EOR in the world, and CO2 flooding is our most 
commonly used EOR technique in the Permian Basin. By using this 
technique, along with other new technologies, we have been able to 
substantially increase the productivity and lengthen the life of 
existing oil fields. Through the use of CO2 flooding and 
other EOR techniques, the fields that Occidental operates in the 
Permian Basin will produce over one billion barrels of oil more than 
would have been produced without this technology. Our experience has 
been that CO2 flooding has increased the ultimate oil 
recovery from the fields where we employ it by an average of nearly 25 
percent. We now operate approximately 8,700 wells in 28 EOR projects in 
Texas and New Mexico utilizing CO2 to increase oil 
production. We have nearly 3,700 CO2 injection wells that 
support 5,000 production wells, and we inject approximately 1.4 billion 
cubic feet of CO2 each day or 500 billion cubic feet per 
year in the Permian Basin alone.
    Using CO2 to enhance the recovery of oil is technically 
challenging and costly. Some oil formations are not amenable to carbon 
dioxide injection, depending on the geologic structure, permeability 
and homogeneity of the formation. For those fields where CO2 
injection is feasible, such as in the Permian Basin, we incur costs 
both to purchase or produce CO2 and to acquire, operate and 
maintain the necessary above-ground processing equipment. Projects are 
capital intensive because they require extensive infrastructure to 
transport, compress, capture and recycle CO2; operating 
costs, such as for additional electricity needs, are also high; and oil 
production response sometimes takes many months to occur. These costs 
add significantly to our total cost to produce a barrel of oil. We 
estimate that using CO2 enhanced recovery at our Permian 
Basin operations increases the cost of recovering a barrel of oil by 
more than 50% over typical primary and secondary recovery operations.
    Notwithstanding the cost, based on our experience in the Permian 
Basin, we believe the use of carbon dioxide to increase oil recovery is 
an extremely important technology for meeting our national energy 
needs, and Occidental encourages Congress to develop policies and 
incentives for increasing the use of this technology. Enhanced oil 
recovery using CO2 has helped increase supplies from some of 
the Nation's most prolific fields. National policies and incentives to 
promote the use of carbon dioxide injection could significantly 
increase proven reserves of oil and gas in the United States. 
Increasing domestic reserves has many additional benefits, including 
extending the life and recoverable reserves of aging reservoirs, 
increasing tax and royalty revenues for the public, increasing 
employment opportunities to operate the fields, and providing greater 
domestic supplies of energy, all of which could, perhaps, reduce or 
forestall speculative exploration in undeveloped areas.
    The Committee has specifically asked for suggestions on how to 
foster further use of carbon dioxide enhanced oil recovery technology 
and to strengthen our domestic oil supply by removing impediments to 
the expansion of this technology. Since CO2 EOR is a costly 
business proposition, these projects require robust long-term economics 
to incentivize the producers to undertake the risk. We have the 
following suggestions on ways to foster further use of this technology:
    1.  Investment incentives:--we suggest you consider providing 
incentives such as investment credits, and accelerated depreciation of 
the project's capital cost, including infrastructure required to 
transport and inject carbon dioxide.
    2.  Royalty rates--we suggest that the government consider 
providing declining royalty rates on federal leases where 
CO2 EOR is used.
    3.  Legal issues--legal areas that warrant clarification include: 
1) confirming subsurface pore-space as part of the mineral estate, 2) 
predictable and defined rights and obligations relating to subsurface 
pore-space ownership, 3) the ability to easily modify historic field 
unit agreements to accommodate EOR operations, including potential 
unitization issues raised by the sequestration of CO2, and 
4) clear expectations regarding the disposition and abandonment of EOR 
wells and fields, including oilfield carbon dioxide sequestration 
sites. However, we believe the current regulatory provisions and 
permitting regimes for conventional CO2 EOR operations work 
very well and provide thorough oversight by the regulators and 
opportunity for public input.
    In addition to these recommendations, I now want to discuss the 
role that CO2 EOR technology can play in controlling 
greenhouse gas emissions. In particular, one of the benefits of 
injecting carbon dioxide for enhanced oil recovery is the ability to 
store significant volumes of carbon dioxide in the reservoir both 
during and after oil and gas production. In typical EOR operations, 
approximately one third to one-half of the carbon dioxide initially 
injected becomes trapped in the reservoir. The rest is recycled from 
oil producing wells as a valuable commodity and reinjected. 
CO2 is not vented to the atmosphere. Additional trapping of 
carbon dioxide occurs with each subsequent injection cycle so that, 
eventually, nearly all of the initial CO2 volume becomes 
stored in the formation and more CO2 must be procured to 
maintain oil production rates. As I mentioned earlier, Occidental 
currently injects approximately 500 billion cubic feet of 
CO2 per year. Of this 300 billion cubic feet is recycled 
CO2 from producing wells, and the other 200 billion cubic 
feet--approximately 40% of the injected CO2--is newly 
supplied to the floods to make-up for the quantity stored through the 
CO2 flooding process. To put this in context, each year the 
amount of CO2 that Occidental injects is equivalent to the 
emissions from ten 150-megawatt coal-fired power plants.
    Occidental has 30 plus years of history using naturally occurring 
carbon dioxide, which we produce from underground reservoirs or buy 
from other producers as a commodity. However, we could just as easily 
use carbon dioxide captured from emissions of electric utilities, 
refineries and other large sources--if it were available at competitive 
prices in the Permian Basin or at other fields suitable for 
CO2 flooding. We believe the key challenges to using man-
made carbon dioxide in EOR operations are the cost of the technology to 
capture carbon dioxide from industrial and power generation sources and 
the cost of building the infrastructure to transport the carbon dioxide 
to an injection site and compress it to a higher pressure that allows 
it to be injected into an oil reservoir for enhanced recovery.
    Additional incentives and policies would be useful to expedite 
building carbon dioxide pipelines and to offset the cost of adding 
equipment to capture and compress emissions containing carbon dioxide. 
Also, since natural CO2 supplies are not available near most 
oil fields that are amenable to CO2 flooding, consideration 
should be given to developing policies and incentives that encourage 
locating new industrial operations and power generation with large 
carbon dioxide emissions near such oil and gas reservoirs. The 
utilization of these man-made CO2 sources would enable more 
widespread application of CO2 EOR to increase domestic oil 
supplies.
    Many organizations are now looking at the underground storage of 
carbon dioxide, which is also known as geological storage or 
sequestration, as an approach to controlling greenhouse gas emissions. 
Occidental sees mutual benefit from the use of carbon dioxide for 
enhanced oil recovery and the storage of carbon dioxide as a way to 
control greenhouse gas emissions. The 2005 special report sponsored by 
the Intergovernmental Panel on Climate Change on carbon dioxide capture 
and storage strongly endorsed the idea and said that EOR technology can 
provide a substantial technical head start on proving the concept of 
geologic storage of carbon dioxide at commercial scale. Occidental 
concurs.
    Occidental also believes that industry experience using 
CO2 for enhanced oil recovery provides technical information 
and demonstrated results for long-term CO2 sequestration. In 
fact, this technology we are using is the gateway to future large scale 
carbon sequestration operations. The industry's 30-year history of 
using CO2 for EOR provides evidence that CO2 can 
be managed safely and should allay concerns about long-term storage of 
CO2 in oil and gas reservoirs as well as other geologic 
formations.
    Occidental believes that, while storing man-made carbon dioxide in 
oil and gas reservoirs and other underground formations is not the only 
option for reducing greenhouse gas emissions, it is an important, 
commercially viable option that can be rapidly implemented to 
accomplish this objective, particularly because it carries with it the 
substantial additional benefit of increasing domestic oil and gas 
production.
    Thank you for the opportunity to speak today and share Occidental's 
experience using carbon dioxide to enhance and increase oil and gas 
production in the United States, as well as our ideas for creating 
policies and incentives to increase its use and expedite development of 
a national infrastructure to capture, transport, inject, recycle and 
store underground carbon dioxide that has traditionally been emitted to 
the atmosphere.
                                 ______
                                 

 Response to questions submitted for the record by William Roby, Vice 
President--Worldwide Engineering and Technical Services, Occidental Oil 
                           & Gas Corporation

1.  Question: Mr. Roby, there are a lot of questions with regard to 
        carbon sequestration. What has the safety record been like in 
        your operations? And do you have any problems with pipeline 
        leaks?
    Response: The safety and environmental record at our 
CO2-EOR operations has been consistently good. As I 
indicated in my testimony our operations have been in existence for 
approximately 30 years and Occidental acquired the assets in 2000. 
During the time of our operation we have had no safety problems related 
to the use of CO2 or its transportation. With regard to 
pipeline leakage, we have typical oil and gas pipelines in the fields 
in addition to the necessary CO2 pipelines. Our pipeline 
system is subject to the normal maintenance issues associated with such 
systems but we have had no safety problems with the handling or 
transportation of CO2. Because the CO2 pipelines 
do not carry volatile substances, they pose much less of a safety and 
environmental risk than typical oil and gas pipelines.
2.  Question: Mr. Roby, what federal and state EOR incentives is your 
        company taking advantage of?
    Response: Section 43 of the Internal Revenue Code has a provision 
for Enhanced Oil Recovery Credit which allows a 15% credit on the cost 
of CO2 (including the transportation to the site) for 
qualified enhanced oil recovery projects where first injection 
commenced after 1990. If a company takes the credit, it then loses the 
deduction for the cost so it nets out to approximately a 10% credit. We 
were able to take advantage of this provision for several years, 
however, the credit phased out when the cost of oil went above the 
inflation-adjusted cap (now approximately $46 per barrel) in 2005. 
Therefore, we have not been able to use this credit since 2005.
    Occidental is actively performing CO2-EOR only in the 
states of Texas and New Mexico and each state treats EOR projects 
differently from a tax standpoint. In New Mexico, EOR incentives are 
available to producers only under certain circumstances. Qualifying 
projects can get relief of 50% of the state severance tax rate, which 
is 3.75%, so the net benefit to a producer would be 1.875%. However, 
this incentive phases out when the price of oil goes above $28 per 
barrel, which it did in 2003. Our North Hobbs Unit began production 
after 2003 and consequently, we have not received any state incentives 
for our New Mexico EOR operations.
    In Texas, incentives are also allowed in certain circumstances. 
Producers may take advantage of a 50% oil severance tax reduction on 
EOR projects approved by the state. The severance tax rate is 4.6% so 
the net tax reduction is 2.3% of the market value of oil produced using 
CO2 injection. Occidental is currently taking advantage of 
this tax provision in Texas.
3.  Question: Mr. Roby, how much natural gas is produced during 
        CO2-EOR operations and what happens to it?
    Response: While the primary target of our CO2-EOR is 
oil, in some cases, we do encounter ``associated'' natural gas. The 
amount of natural gas produced varies from field to field and from well 
to well and is not easy to quantify in the abstract. Generally, the 
natural gas is captured and sent to a processing plant where the 
CO2 and other compounds are removed; then the natural gas is 
put into a pipeline and sold. In our operations, we use the recovered 
CO2 again in EOR operations.
4.  Question: Mr. Roby, what sort of production levels could we see 
        from CO2-EOR over the next 10 to 20 years? Could we 
        reach 1 million barrels a day? What would it take to make those 
        sorts of production levels a reality?
    Response: Currently, the U.S. produces about 200,000 barrels of oil 
per day (BOPD) using CO2-EOR with about 180,000 of those 
barrels being produced in the Permian Basin of Texas and New Mexico. As 
I indicated in my testimony, fields respond differently to 
CO2-EOR and some fields are simply not responsive to 
CO2 or geologically amenable to the application of 
CO2-EOR technology. In order to substantially increase the 
recovery of oil using CO2-EOR, it will be necessary to 
ascertain whether a particular field is amenable to CO2-EOR, 
find sources of CO2 and then build the infrastructure to get 
the CO2 to the fields. Ultimate production levels will, of 
course, depend upon the costs of each project and the price of oil. It 
is certainly possible that production could reach 1mm barrels per day 
given adequate CO2 and investment in infrastructure; 
however, this level of production is unlikely in the foreseeable future 
absent some governmental incentives. Using the current U.S. production 
as an analog, our industry has grown production 200,000 BOPD over the 
past 20 years. This suggests that CO2 induced production 
could be in the 300,000 to 400,000 BOPD range over the next 10-20 years 
unless unusual investment incentives are undertaken.
                                 ______
                                 
    Mr. Costa. I want to be fair to all the witnesses in terms 
of the timing, and you exceeded your time. But we do appreciate 
your testimony.
    Our next witness is Mr. Greg Kunkel. You are Vice President 
of Environmental Affairs in Tenaska, Inc., is that correct?
    Mr. Kunkel. That is correct.
    Mr. Costa. Wonderful. Please begin your testimony.

    STATEMENT OF GREG KUNKEL, VICE PRESIDENT, ENVIRONMENTAL 
                     AFFAIRS, TENASKA, INC.

    Mr. Kunkel. Thank you, Chairman Costa, Ranking Member 
Pearce, and members of the Subcommittee.
    My name is Dr. Greg Kunkel, Vice President of Environmental 
Affairs at Tenaska. And I am pleased to be here to share our 
views on enhanced oil recovery.
    Tenaska is one of the nation's top developers of large, 
efficient power-generation facilities. In fact, the Natural 
Resource Defense Council ranks Tenaska as having the lowest 
carbon footprint of any of our peers, with less than half of 
the national average emission rate of greenhouse gases.
    Tenaska's record demonstrates that significant greenhouse 
gas emission reductions can be accomplished in the power sector 
using low-carbon fuels, like natural gas, and advanced 
combined-cycle technology.
    Today, however, I am here to talk about achieving even 
more, and not with natural gas, but with coal, with the help of 
the oil industry, and potentially with your help.
    Over the last several years, high and volatile natural gas 
prices have stimulated a growing demand for baseload electric 
generation resources, like coal and nuclear, with lower and 
less volatile fuel costs, and 24-hour-per-day operation.
    Because market conditions were obvious to everyone, many 
coal-fired facilities were proposed, and many advanced to some 
stage of development. Some have been, or are being, built, but 
many more have been postponed or canceled due to uncertainty 
about future legislative caps on greenhouse gas emissions, 
among other things.
    Tenaska has concluded that baseload generation using coal 
is still very necessary to avoid soaring electricity prices in 
the future. But the control of greenhouse gas emissions in the 
most cost-effective manner should be a part of any future coal 
development.
    We believe that enhanced oil recovery has an important role 
to play in achieving cost-effective emission control for early 
adopters of carbon emission control technology.
    Currently, Tenaska has an early development of commercial-
scale coal-fired baseload power facilities that is unlike any 
currently in operation. Tenaska's objection has been to find 
ways to develop the baseload resources that the market for 
electricity requires.
    In enhanced oil recovery, we see a way to do that and 
provide carbon dioxide as a commodity in an existing market, in 
which the end use also accomplishes geologic storage.
    The Tenaska Trailblazer Energy Center, located near 
Sweetwater, Texas, in the Permian Basin, where the best EOR 
opportunities exist, is designed to capture up to 90 percent of 
its potential carbon dioxide emissions, and deliver that 
CO2 via pipeline for use in enhanced oil recovery. 
Trailblazer will utilize super-critical pulverized coal 
technology, and we are considering adding carbon dioxide-
capture technologies, among others.
    While Tenaska is fully focused on developing Trailblazer, 
and it could be in operation as early as 2014, it is important 
to recognize that we have developed this project in 
anticipation of Federal climate change legislation that offset 
the significant capital and operating costs of carbon-capture 
technology.
    Without a carbon regulatory regime to ensure that avoidance 
of greenhouse gas emissions has a monetary value, it appears 
that revenues from enhanced oil recovery carbon dioxide sales 
will be insufficient to cover all carbon-capture costs. 
However, if carbon emissions are regulated, projected 
compliance cost savings and other regulatory effects, combined 
with EOR revenues, would provide the needed economic incentives 
to build Trailblazer.
    Perhaps the most important thing Congress could do to 
facilitate the development of Trailblazer or other similar CCS 
projects is to provide industry with regulatory certainty, 
particularly a regulatory framework within which a market can 
develop that values greenhouse gas emission reductions.
    In the past, Congress has employed a number of effective 
policies to help overcome barriers to entry and encourage new 
energy technologies. Tenaska generally supports those 
mechanisms that provide the greatest degree of certainty; we do 
a lot of financing. We prefer investment tax credits and 
accelerated depreciation to Federal grants or loan guarantees, 
primarily because of predictability.
    Should the House decide to pursue a cap-and-trade 
mechanism, some of the potential areas where the specifics of 
climate change legislation could affect the project are 
allowance allocations, use of auction proceeds, mobilization of 
equipment manufacturers and others in the industry, necessary 
regulation, and electricity pricing.
    In summary, proven technology is available today to capture 
greenhouse gases from coal-fired power plants, and the value of 
carbon dioxide-enhanced oil recovery makes that technology 
cost-effective if we also value a reduction in greenhouse gas 
emissions.
    As previously acknowledged, Trailblazer was conceived and 
has been designed in anticipation of Federal climate change 
legislation. In the absence of such legislation, Trailblazer 
faces costs and risks that likely cannot be offset by revenues 
from EOR.
    For the benefit of demonstrating carbon capture and storage 
at commercial scale, Congress may elect to support a few 
carbon-capture projects, and we would hope that cost-effective 
projects associated with EOR will be given some consideration 
in that event.
    Thank you again for your interest in this subject. I would 
be pleased to respond to any questions at the right time.
    [The prepared statement of Mr. Kunkel follows:]

       Statement of Gregory P. Kunkel, Ph.D., Vice President of 
                  Environmental Affairs, Tenaska, Inc.

    Thank you Chairman Costa, Ranking Member Pearce and Members of the 
Subcommittee.
    My name is Dr. Greg Kunkel. I am Vice President of Environmental 
Affairs for Tenaska, Inc., and I am pleased to be here to share our 
views on opportunities for enhanced oil recovery using carbon dioxide 
captured from a power plant. I believe Tenaska can provide important 
insight to Congress on this matter because of an electric generation 
project Tenaska has in early development: a commercial-scale, coal-
fired, baseload power facility that, unlike any currently in operation 
anywhere, would capture up to 90 percent of its potential carbon 
dioxide (CO2) emissions and deliver that CO2 for 
use in enhanced oil recovery operations and geologic storage.
    Tenaska is a privately held company that builds, owns and operates 
power plants, among other business activities detailed at the end of 
this testimony. Congress and developers of power plants share some 
common interests concerning climate change legislation. You and I both 
want to know what it will cost to eliminate greenhouse gas emissions 
from power generation through carbon capture and storage technologies. 
If the answer to this was well known, then climate change legislation 
could be crafted that would pose less risk to the economy. From the 
perspective of the electric industry, technological risks for the first 
commercial carbon capture and storage facility are compounded by the 
fact that federal greenhouse gas cap-and-trade or other governing 
regulatory structures do not yet exist, and it is unclear whether state 
or regional regulatory structures will prevail over the long term. 
International obligations have not been finalized. Whereas industry 
looks to Congress for a structured market with rules, Congress 
reasonably looks to industry for at least a preliminary estimate of the 
costs.
    Academics, policy makers and even the leadership of the G8 
countries seem to agree that the country, and the world, needs a number 
of large-scale carbon capture and storage projects that will resolve 
critical technical and economic feasibility issues. Tenaska believes 
that enhanced oil recovery (EOR) can contribute to advancement of such 
a project by simultaneously providing for geologic storage of 
CO2 and a significant economic benefit that could help to 
pay for early deployment of carbon capture technology. Whatever the 
costs for carbon capture and storage will be, and I do not have a final 
answer for you on that, I do know that net costs will be less if we can 
make economic use of the CO2. The testimony that follows 
describes how Tenaska became interested in EOR, the development status 
of our project, and some thoughts on what Congress can do to advance 
commercial deployment of baseload generation with carbon capture and 
storage.
Challenge: Building Baseload Generation in an Uncertain Regulatory 
        Environment
    Tenaska is one of the nation's top developers of large, efficient 
power generation facilities. The Natural Resources Defense Council 
ranks Tenaska as having the lowest carbon footprint of any of our 
peers--less than half of the national average emission rate of 
greenhouse gases. As developers, rather than researchers or inventors, 
Tenaska's focus is on projects that can be accomplished with available, 
reliable, cost-competitive equipment and for which development 
investments can be made with a reasonable assurance of success.
    Over the last several years, market conditions for development of 
generation facilities have included high and volatile natural gas 
prices, oversupply of natural gas generation capacity in much of the 
country, financial failures of merchant generators, regional growth in 
renewable energy resources, and growing demand for ``baseload'' 
resources, like coal and nuclear, with lower and less volatile fuel 
costs and 24-hour-per-day operation. Many coal-fired facilities 
advanced to some stage of development, some have been or are being 
built, but many more have been postponed or canceled due to various 
combinations of escalating costs, environmental opposition, utility 
owner and commission concerns about long-term investment in coal, and 
uncertainty about future environmental and climate change-related 
requirements.
    Tenaska's objective has been to find ways to develop the baseload 
resources that the market for electricity requires. We were reticent to 
invest in solid fuel projects without addressing the climate change 
issue, so a question before us was how to reduce greenhouse gas 
emissions in the design of projects today. To accomplish this, we 
needed to assure ourselves that carbon capture technologies were ready 
for a utility-scale project; a secure home was available for captured 
CO2; and the economics and long-term financing arrangements 
for such projects would work.
New Coal Plants with Carbon Capture: Enhanced Oil Recovery as a 
        Business Opportunity
    In enhanced oil recovery (EOR), Tenaska saw an attractive market 
for CO2 in which geologic storage is accomplished under an 
existing, federal regulatory structure. Interviews with oil producers 
with EOR expertise suggested a considerable appetite for additional 
supply. However, the current opportunities to meet this demand are 
geographically limited, and significant barriers exist to new EOR 
development. Pipelines for transporting CO2 are specialized, 
high-pressure pipelines with relatively high construction costs, so the 
distance between the source and the injection sites is critically 
important.
    Tenaska embarked on feasibility studies to evaluate whether a coal-
fired generation facility with carbon capture capability could be 
economically developed in or near the Permian Basin, where a robust EOR 
market exists. We focused on coal sourced from the Powder River Basin 
that would be delivered by rail. We reviewed greenfield and brownfield 
pulverized coal as well as integrated gasification combined cycle 
(IGCC) generation technologies, but ultimately selected supercritical 
pulverized coal with amine CO2 capture technology for 
further work.
    Some of the well-known advantages of IGCC technology with respect 
to CO2 capture efficiency are to some degree offset by 
reduced efficiency of combustion turbines at the altitude of West Texas 
sites. Supercritical pulverized coal technology enjoyed a relative 
advantage in our analysis with respect to equipment availability, cost 
certainty, reliability, industry experience, competitive procurement 
and development costs. Amine-based CO2 absorber/stripper 
systems have been in operation on smaller scales and represent the more 
mature technology available for utility carbon capture applications. 
Tenaska continues to evaluate alternative technologies, including 
ammonia-based systems.
    In October, 2007, Tenaska committed funding for engineering, site 
development, and permitting of a supercritical pulverized coal facility 
with carbon capture to serve the Electric Reliability Council of Texas 
(ERCOT) and Permian Basin EOR markets. The ERCOT power market provides 
good opportunities for a facility of the sort we are proposing. It has 
a need for baseload power and the ERCOT transmission system is located 
in suitable proximity to the Permian Basin, where good EOR 
opportunities exist. In addition, it is a market with which Tenaska is 
very familiar. We have developed approximately 3,500 MW of generation 
capacity in ERCOT, and our power marketing group is headquartered 
there.

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Tenaska's Trailblazer Energy Center
    On February 19, 2008, Tenaska publicly announced the Trailblazer 
Energy Center, a 765 MW gross output and 600 MW net output 
supercritical pulverized coal electric generation facility with the 
capability to capture and deliver to the EOR markets 90 percent of 
CO2 produced in the boiler. On the same day, we closed the 
site property transaction, an air permit application was filed with the 
Texas Commission on Environmental Quality, and a transmission 
interconnect request was filed with ERCOT.

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 Tenaska is fully focused on the development of Trailblazer. Our 
schedule calls for completion of studies to support engineering, 
procurement and construction contracting as well as issuance of key 
environmental permits by the first quarter of 2009. Financial closing 
and initiation of construction may be as early as the fourth quarter of 
2009. Construction requires about four and half years, so commercial 
operation could be as early as 2014. Currently, we are performing 
technical and economic analyses of competing carbon capture 
technologies and vendor offerings; transmission studies are underway; 
water resource studies are in process; and intensive permitting and 
site development work is ongoing.
    Merits of Trailblazer include the following:
      600 MW of needed baseload generation capacity to the 
ERCOT electric transmission grid.
        Addition of baseload power reduces marginal power prices 
to the benefit of consumers across the system.
        Coal-fired capacity helps insulate Texas electric 
customers against natural gas price volatility.
      Enhanced Oil Recovery and Carbon Sequestration
        Availability of CO2 renders a greater fraction 
of the original oil in place recoverable, thereby adding to recoverable 
reserves.
        Actual production of oil is increased. If the historical 
Permian Basin EOR response is used as a guide, this could mean more 
than 34,000 incremental barrels of oil per day associated with 
Trailblazer's 300 million cubic feet per day of CO2.
        Recapture and re-injection of CO2 produced with 
the oil can provide a high percentage of permanent geologic storage of 
the gas.
      Economic Impact
        Provide 1,500 to 2,000 jobs over a lengthy construction 
period.
        Create more than 100 permanent and well-paying jobs.
        Stimulate the local economy with construction spending 
over $2 billion and a total project cost over $3 billion
        Enable $1 billion incremental Permian Basin oil production 
annually.
        Reduce the rate of decline of U.S. production and 
dependence on imported oil.
      Environment
        Post-combustion capture, if successfully demonstrated on 
this scale, could have a wider application. Indeed, our investigation 
indicates that retrofitting existing coal stations with CO2 
capture technology may have about the same cost as the addition of this 
equipment to a new facility. According to the Intergovernmental Panel 
on Climate Change (IPCC), there are about 5,000 large power plants 
worldwide with combined emissions of over 10 billion tons of 
CO2 per year.
        Higher levels of sulfur dioxide (SO2) removal will likely 
be needed, pushing criteria pollutant emissions control to a new level.
        An opportunity is presented for recapture of flue gas 
water that may enable gains in water use efficiency.
        Trailblazer may also utilize air cooling or hybrid cooling 
systems that further decrease water requirements.
        Expanded production of oil from existing fields has less 
impact than development of new fields.
Commercial Challenges Facing Trailblazer
    For Trailblazer to become a commercial enterprise, there are 
significant challenges to overcome. Many of the more substantive 
challenges relate directly to the carbon capture and storage component. 
The costs of carbon capture using existing technology scaled to 
utility-sized application are daunting. The capital investment in 
carbon capture could add as much as a $1 billion to a $2 billion power 
plant, when financing and other ``soft'' or indirect costs are 
included. There are ongoing operating costs as well. At Trailblazer, 
the equivalent of 200 MWs of electricity and steam may be consumed in 
the CO2 capture and compression process that otherwise would 
be delivered to the ERCOT power grid.
    There are other, less direct ``early-adopter'' costs associated 
with introducing new technology that will affect Trailblazer. New 
technologies carry inherent risk. Until the first commercial plant is 
built and operated, and the risks have been quantified, each 
participant in the development, construction, and financing process 
will place a risk premium on their participation to cover unknown but 
real contingencies. Once there is a suitable track record for 
commercial utility-scale carbon capture technology, associated risks 
can be assumed by those most capable of mitigating them and the risk 
premium will be reduced.
    Since announcing Trailblazer in February, my colleagues and I have 
been busy explaining the project to local and regional stakeholders and 
policymakers and also to staff and Members of Congress here in 
Washington. The response has been generally very supportive, even among 
groups and individuals long opposed to new additions of coal-fired 
generation capacity. To maintain that support, we recognize that 
continued engagement will be needed throughout the development process, 
and we have much yet to do.
Impact of Federal Polices on Trailblazer
    Perhaps the most important thing Congress could do to facilitate 
the development of Trailblazer or similar carbon capture and storage 
projects, is to provide regulatory certainty, and in particular, a 
regulatory framework within which a market can develop that values 
greenhouse gas emission reductions. Without regulatory certainty and 
recognition of the value of emission reductions, developers are 
confronted with making multibillion dollar decisions in a policy 
vacuum. No developer can operate effectively while having to speculate 
on regulatory outcomes, especially outcomes so fundamental to the 
success of the enterprise.
    Accordingly, we have developed Trailblazer in anticipation of 
federal climate change legislation that would support, through placing 
a price on greenhouse gas emissions and other means, the significant 
capital and operating costs of carbon capture technology. Without 
climate legislation, it appears that revenues from enhanced oil 
recovery CO2 sales will be insufficient to cover all carbon 
capture costs. With proposed climate legislation, projected compliance 
cost savings and other effects of climate change legislation, combined 
with EOR revenues, would provide the needed economic incentives to 
build and operate Trailblazer.
    Some of the potential areas where climate change legislation could 
affect the project are:
      Allowance allocation. Most cap-and-trade legislative 
proposals include some free allocation of emission allowances for new 
sources, and may include bonus allowances for generation units with 
carbon capture and storage.
      Auction proceeds. Cap-and-trade proposals may produce 
governmental revenue by auctioning greenhouse gas emission allowances 
to regulated entities. Auction proceeds may be directed to construction 
of early carbon capture and storage projects or performance payments 
for demonstrated sequestration.
      Industry mobilization. Utility equipment manufacturers, 
financial institutions and service providers would be encouraged to 
bring forward competitive new offerings to address the risks and 
opportunities of a large new market. To some degree, this is occurring 
in advance of legislation, but is clearly a result of the industry's 
sense that climate change legislation is inevitable within the next 
couple of years. An interesting byproduct of our investigation of 
capture technologies is that there does not appear to be an 
insurmountable cost penalty for retrofit applications. This implies a 
potential to apply similar technology to much of the nation's existing 
fossil fleet.
      Regulatory framework. Climate change legislation will 
likely provide for further regulatory development to provide for the 
establishment of greenhouse gas registries, industrial emission 
monitoring rules, permitting, monitoring and verification of greenhouse 
gas sequestration sites; and address long term liability for geologic 
storage sites. Sequestration achieved through EOR needs to be 
specifically recognized in such regulations. Development of the 
regulatory framework is critically important.
      Increased electricity price. Almost any kind of climate 
change legislation will associate a cost with emissions of greenhouse 
gases such as CO2. Because of compliance costs of 
uncontrolled generation facilities, higher market electricity prices 
can be expected.
    In the past, Congress has employed a number of effective policies 
to help overcome barriers to entry and encourage new energy 
technologies. We support those mechanisms that provide the greatest 
degree of certainty with respect to their application and that have 
clearly established guidelines. We prefer investment tax credits more 
than federal grants or loan guarantees primarily because the 
predictability of receiving tax policy benefits is greater and more 
controllable than the possibility of being awarded a grant or loan 
guarantee by a federal agency. Such accounting practices as an 
accelerated depreciation standard applied to the carbon capture 
component of Trailblazer would facilitate faster recovery of investment 
capital, and would provide a material incentive that we and our 
financing counterparties could evaluate with a higher degree of 
certainty. Absolving early sequestration projects from CO2 
liability would similarly facilitate more enthusiastic participation by 
the financial community.
    Should the House decide to pursue a cap-and-trade mechanism similar 
to what has been contemplated in the Senate, we would advocate for an 
economy-wide approach. We would support bonus provisions for early 
adopters, and for EOR to be eligible for the same level of benefits as 
other CO2 sequestration mechanisms. We would prefer that 
natural gas be regulated upstream from the emission source, to 
encompass a greater number of emitters while regulating fewer sources, 
and to avoid cost-recovery issues for entities holding long-term power 
delivery contracts.
Conclusion
    Tenaska confronts many significant challenges in its effort to take 
the Trailblazer project from concept to reality. Trailblazer has been 
designed in anticipation of federal climate change legislation. In the 
absence of such legislation, Trailblazer faces costs and risks that 
likely cannot be offset by revenues from power generation and marketing 
CO2 for enhanced oil recovery. Trailblazer can wait until 
federal legislation is enacted or Congress can act in other ways to 
support such a project now.
    Thank you again for your interest and for the opportunity to 
provide some details on this exciting project. I would be pleased to 
respond to any questions you may have.
About Tenaska
    Tenaska is an energy company that develops, constructs and operates 
non-utility electric generation and cogeneration facilities that it 
owns in partnership with other companies. The company also markets 
natural gas, electric power and biofuels and provides energy risk 
management services. In addition, Tenaska is involved in asset 
acquisition and management, fuel supply, natural gas transportation 
systems and electric transmission development. Tenaska was founded in 
1987, and is a privately held company with headquarters in Omaha, 
Nebraska, and regional offices in Texas, Colorado, and Alberta, Canada. 
The company currently has more than 600 employees; 2007 gross operating 
revenues were $11.6 billion.
    Tenaska has considerable experience as a developer of electric 
power generation, having built more than 9,000 megawatts of highly 
efficient, state-of-the-art power generation facilities associated with 
more than $10 billion in total financial transactions.
                                 ______
                                 

 Response to questions submitted for the record by Greg Kunkel, Ph.D., 
          Vice President, Environmental Affairs, Tenaska, Inc.

1.  Dr. Kunkel, if your project requires a cap-and-trade system to 
        become economic, and you're getting revenues from selling the 
        carbon dioxide for EOR, does that mean that a cap-and-trade 
        system by itself wouldn't get companies to capture carbon 
        dioxide unless there was an enhanced oil recovery option?
    Response: EOR should make carbon capture economic sooner than it 
would be otherwise. Any of the proposed cap-and-trade systems would 
have the benefit of providing a price signal that companies could use, 
among other factors, to guide investment decisions related to carbon 
dioxide capture facilities. Economic analyses of various cap-and-trade 
proposals suggest that those price signals, particularly the implied 
operating cost related to emitting each ton of carbon dioxide or other 
greenhouse gas, would likely be below the level that would justify 
carbon capture in the early years of cap-and-trade system 
implementation. As the emissions allowed under the cap are reduced over 
time, then we expect that emissions allowance pricing would eventually 
justify carbon capture, based also on our current understanding of 
carbon capture capital and operating costs. By 2050, when emissions 
reductions of 50 to 80 percent may be required, it is clear that carbon 
capture must be and would be widely implemented for generation 
facilities that utilize fossil fuels.
    EOR revenue has the effect of rendering carbon capture economic at 
the earliest possible date. By effectively making the cost of emissions 
reductions lower, EOR can reduce the costs of any cap-and-trade 
program.
    In addition to the price signal provided by any cap-and-trade 
system, auction of emission allowances would also provide revenues that 
could be directed toward early emission reduction actions, like carbon 
capture. A cap-and-trade system can also be designed to provide bonus 
allowances for carbon capture. From Tenaska's perspective, such 
incentives are most effective when the economic benefit is very clear, 
such as a defined payment for each ton sequestered, so that any benefit 
is deemed credible by investors and lenders.
    Another important consideration is the general state of capture 
technology. Current pilot testing and demonstration projects for new 
technologies and full scale design and construction of the first 
utility scale projects will reduce uncertainty in our cost estimates, 
demonstrate the limits of performance of alternative capture 
technologies, and pave the way for lower cost capture facilities in the 
future.
2.  Dr. Kunkel, what percentage of carbon dioxide do you estimate you 
        will capture at your plant?
    Response: Tenaska's ongoing review of carbon capture technologies 
for post-combustion applications indicates that we will be able to 
design a facility to achieve 85 to 90 percent capture of carbon 
dioxide. We intend to capture this percentage from the entire flue gas 
stream, not just a side stream as proposed in various pilot projects.
    I would like to thank the Subcommittee Members and Staff for their 
interest in Tenaska's Trailblazer Project and the potential for carbon 
capture from power facilities to support enhanced domestic production 
of oil.
                                 ______
                                 
    Mr. Costa. Thank you, Dr. Kunkel, for your very good 
testimony.
    Our next witness is Dr. Ian Duncan, Associate Director from 
the Earth and Environmental Systems, Bureau of Economy Geology 
for the University of Texas at Austin. Is that correct?
    Mr. Duncan. The Bureau of Economic Geology.
    Mr. Costa. At the University of Texas.
    Mr. Duncan. At the University of Texas at Austin. Yes, sir.
    Mr. Costa. I understand you have a good school down there.
    Mr. Duncan. That is the rumor.
    Mr. Costa. We are glad to have you here. Please begin your 
testimony.

    STATEMENT OF IAN DUNCAN, ASSOCIATE DIRECTOR, EARTH AND 
    ENVIRONMENTAL SYSTEMS, BUREAU OF ECONOMIC GEOLOGY, THE 
                 UNIVERSITY OF TEXAS AT AUSTIN

    Mr. Duncan. I appreciate the opportunity to testify. I 
would first say that the Chairman has stolen most of my thunder 
and made most of my points, but I will try to add a few things 
to his remarks.
    Mr. Costa. Good points are always worth underlining, 
especially when you agree with the Chairman.
    Mr. Duncan. CO2-enhanced oil recovery can impact 
atmospheric CO2 levels in a significant way. 
Currently, in the Permian Basin on Texas, 30 million tons a 
year of CO2 are being injected into depleted 
oilfields. Approximately 15 percent of this is coming from 
industrial sources currently. I believe that 99 percent, give 
or take half a percent, of that CO2 actually ends up 
in long-term storage in the subsurface.
    We have over 35 years of history of CO2 
injection in the Permian Basin. And this really makes this a 
real interesting laboratory to look at the effects of 
CO2 in the subsurface. Several people have mentioned 
leakage. Our biggest hope for understanding leakage is to look 
at these longstanding floods in the Permian Basin. And it is 
unfortunate that, apart from the small project that the Bureau 
has running, there is very little study of this at the moment.
    Government can encourage early entry capture projects. As 
Tracy Evans said, this is going to be critical to get 
CO2-enhanced oil recovery going based on 
anthropogenic CO2. In fact, what we need to do is 
transition from business-as-usual CO2 EOR to what I 
would call next-generation CO2 EOR.
    Business as usual is mostly using natural CO2 
uses technologies that minimize CO2 usage for 
historical reasons, has limited monitoring, and mostly takes 
place in 80 percent of the Permian Basin of Texas, and results 
in about 15 percent, give or take, additional oil recovery.
    Next-generation enhanced oil recovery could be based mostly 
on anthropogenic CO2, if we can get the capture, 
should maximize CO2 usage using new technologies, 
some of which are on the horizon, but need further research; we 
will have sequestration-grade monitoring, or MMV; we will have 
higher-percentage oil recoveries, and will spread out across 
the country to multiple states in multiple sedimentary basins.
    CO2-enhanced oil recovery can play a major role 
in paying for the infrastructure that can be later used for 
sequestration on a large scale in brine reservoirs.
    We at the Bureau have estimated that 3.8 billion barrels of 
oil are available outside the Permian Basin in Texas that could 
be gained through CO2-enhanced oil recovery. We also 
need more trained personnel if we are going to ramp up. We need 
more graduate student research, more DOE grant funding, to 
train the personnel that we need to do this.
    A lot of the people in this industry are my age, and are 
going to be retiring over the next five to 10 years. Personnel 
is a major issue. I think we also need an aggressive research 
program to help increase oil recovery as this next generation 
approaches, and lower risk.
    Thank you, Mr. Chairman.
    [The prepared statement of Mr. Duncan follows:]

           Statement of Ian Duncan, PhD, Associate Director, 
       Bureau of Economic Geology, University of Texas at Austin

    My name is Ian Duncan. I have a PhD in Geological Sciences and I am 
an Associate Director of the Bureau of Economic Geology (BEG) at the 
University of Texas at Austin. The BEG is engaged in a wide range of 
applied research in a broad range of energy related and environmental 
issues including CO2 sequestration. The BEG's Gulf Coast 
Science Center (GCCC) part of my group is an industry-academic 
collaboration that has been working on geologic CO2 storage 
including CO2 EOR since 1988. The GCCC currently has 
significant field tests underway, one Scurry County Texas (Kinder 
Morgan's SACROC CO2-EOR field) and two in Mississippi 
(Denbury resources Cranfield CO2-EOR sit). These field tests 
seek to how effectively CO2 injected for EOR is retained in 
the subsurface, and how we can best predict and document this retention 
through modeling and monitoring. These studies are funded by about $50 
million in Department of Energy funds (over 10 years). For the past 
nearly four years I have been doing research on the role that 
CO2 Enhanced Oil Recovery (CO2-EOR) can play in 
mitigating greenhouse gases in the atmosphere and in increasing 
domestic oil production in the US.
    The key points that I would like to make are:
    (1)  In the near term CO2-EOR can make a significant 
contribution to mitigating increases in CO2 emissions into 
the atmosphere by putting significant quantities of anthropogenic or 
man-made CO2 (CO2-A) into permanent storage in 
depleted oil reservoirs
    (2)  Government should encourage ``early-entry'' capture at power 
plants and other industrial sources of CO2 emissions to 
supply CO2-A for CO2-EOR projects in conjunction 
with sequestration. It is critical that these projects be allowed 
qualify for whatever carbon credits or offsets arise out of federal 
legislation.
    (3)  Government should provide a policy/regulatory environment that 
encourages CO2 EOR operators to change business as usual by: 
a) utilizing CO2-A when made available at a reasonable cost 
from capture at power plants and other industrial sources; b) creating 
and implementing monitoring, verification and mitigation (MMV) plans to 
provide assurance of permanent sequestration; and c) conduct life cycle 
analyses of their projects to measure CO2 avoided.
    (4)  CO2-EOR can provide the financial capacity and 
rationale for developing a CO2 capture, compression and 
transportation infrastructure across a significant portion of the U.S. 
that can later be used for large scale CO2 sequestration in 
deep brine reservoirs.
    (5)  In the Texas Gulf Coast alone, BEG staff have estimated that 
an additional 3.8 billion barrels of oil recovery could be achieved 
through CO2-EOR. This is almost twice the entire annual 
domestic oil production of the U.S. at this time.
    (6)  Industry and University experience related to CO2-
EOR in the U.S. has provided most of the knowledge, expertise and human 
capacity that will enable CO2 sequestration to be 
implemented. Creating funding for CO2-EOR related research 
in the Department of Energy's budget could have a significant positive 
effect on knowledge creation, technological innovation and technology 
transfer related to CO2 sequestration. Such funding would 
also help produce young engineers and geologists trained in 
CO2 injection related technologies and help alleviate a 
shortage that is critical now and will grow more so in the near future.
    (7)  An aggressive research program including pilot projects would 
help improve the performance of current EOR activity and enable the 
development of new more effective approaches that could increase oil 
recovery, reduce the geological and technical risks, and enhance 
sequestration rates incidental to CO2-EOR.
    CO2 sequestration will involve the capture anthropogenic 
CO2 (typically from electric power plants) followed by deep 
subsurface injection into oil and gas reservoirs, deep unmineable coal 
beds or deep brine reservoirs. Approximately 80% of the CO2 
injection in the world takes place in the Permian Basin of Texas and 
New Mexico, making the region the largest commercial market for 
CO2. Texas corporations and technical workers have a unique 
experience base and outstanding safety record, in pipeline transport 
and subsurface injection of CO2. Since the early 1970s, 
CO2 has been injected into many Permian Basin oil reservoirs 
to enhance production. Injected CO2 is dominantly produced 
from natural accumulations and pipelined to the Permian Basin. In 
addition, on the order of 10% is now derived from other sources such as 
gas processing plants where the CO2 would otherwise have 
been released to the atmosphere. Currently roughly 30 million metric 
tons (MMt) of CO2 are injected annually in the Permian Basin 
in operations that are closed-cycle. In other words, CO2 
that is produced from the oil reservoirs in association with the 
recovered oil is recycled (re-injected into the reservoir for 
additional recovery).
    Many individual operations in the Permian Basin are at the scale of 
CO2 production associated with coal burning power plants. 
CO2-flooding for enhanced oil recovery (EOR) has been active 
at SACROC in Scurry County since 1972. Kinder Morgan the current 
operators at SACROC currently inject 13.5 MMt CO2/yr and 
withdraw/recycle 7 MMt CO2/yr, for a net storage of 6.5 
MMt CO2/yr. For comparison, a 500 MW pulverized coal power 
plant produces roughly 3-4 MMt CO2/yr. This magnitude of 
annual CO2 storage at SACROC is over six times the rate of 
Statoil's Sleipner project offshore Norway.
    The Gulf Coast has a large potential for CO2 enhanced 
oil recovery (EOR) outside of the traditional area of CO2 
EOR in the Permian Basin. Using the miscibility screening criteria BEG 
staff have inventoried 767 oil reservoirs where miscible CO2 
EOR could be applied for an additional 3.8 billion barrels of oil 
recovery. By way of comparison, annual oil production in USA is about 
1.86 billion barrels. This incremental production target is attractive 
because of value in terms of wellhead value, tax revenue, and economic 
activity. This EOR activity would lead to the use of large amounts of 
CO2, however, it is small in the context of the projected 55 
to 70 billion tons of CO2 emissions for the Gulf Coast over 
the next 50 years. Deep brine reservoirs in the Gulf Coast have been 
estimated by BEG staff to have a sequestration capacity about 4 times 
this value (that is over 200 billion tons of CO2).
    EOR results in storage of CO2 dissolved in residual oil, 
dissolved in brine, and trapped as an immobile supercritical phase. 
Experience in Permian basin EOR projects is that 30 to over 60% of the 
injected CO2 is retained in the reservoir during the first 
pass through the reservoir. Ultimately through recycling 99.. However, 
the volume retained as a by-product of EOR is small relative to total 
point source emissions. The large synergy between EOR and reducing 
carbon emissions is that EOR would enable the construction of an 
infrastructure linking sources to reservoirs. Very large volumes of 
brine reservoirs can then be accessed beneath oil production, a concept 
that we describe as stacked storage. Existence of an infrastructure 
would reduce the cost of storage of Gulf Coast power plant, refinery, 
and chemical plant emissions for the next 50 years or more.
    The Gulf Coast of the USA is a region of high CO2 
emissions that overlie thick, extensive, and well known subsurface 
geologic formations. Path forward toward developing an economically 
viable system for capture and storage include: (1) development of a 
climate favoring construction of gasifiers using coal, lignite, petcoke 
and/or biomass as sources (IGCC electric power plants for example), (2) 
construction of a pipeline backbone to transport CO2 
regionally, (3) a market for CO2 for EOR in areas beyond the 
traditional area of use in the Permian Basin, and (4) development of 
stacked storage, using deeper brine-bearing formations beneath 
hydrocarbon reservoirs.
    Sequestration credits may play a significant role in future 
CO2 EOR based on anthropogenic CO2. The criteria 
to qualify projects for CO2 credits are likely to evolve as 
the industry matures. A recent Texas law creating a tax credit for 
CO2 EOR using anthropogenic CO2 requires projects 
to establish a reasonable expectation that they can meet a performance 
standard of 99% retention for 1,000 years. To meet this standard, 
operators will likely have to: characterize the seal for their 
reservoir and demonstrate that it is compatible with this standard; 
design and implement an appropriate monitoring program and complete a 
CO2 life cycle analysis to verify the amount of 
CO2 avoided.
    Up until now, CO2 purchase has been the largest cost 
component of a CO2-EOR flood. As a result engineers and 
geologists in companies and the Universities have developed and refined 
technologies and approaches to minimize CO2 usage in 
CO2-EOR projects. We may be entering a new regime in which 
CO2 injection gains credits that changes the fundamental 
economics. Under these circumstances new or previously little used 
approaches to CO2 EOR projects such as vertical floods and 
CO2 alternating with CO2 foam may become viable. 
Such approaches offer great opportunities for increasing the total oil 
recovery and maximizing CO2 storage. However research in 
combination with full scale field test are almost certainly necessary 
to convince companies of the viability of these and other ``game 
changing'' technologies.
    Although this testimony has focused on the Gulf Coast and Permian 
basin of Texas, significant CO2-EOR potential also exists in 
a number of other states including Louisiana, New Mexico, Oklahoma, 
Wyoming, Illinois, Michigan, California, Kansas, Mississippi, North 
Dakota and others. In the context of economic growth, global oil demand 
and atmospheric mitigation of CO2, a ``first step'' 
mechanism is required to sequester large volumes of CO2 in a 
manner that later allows pure CO2 storage to initially 
``piggyback'' via the commercial leverage of the oil recovered.
    In summary I would leave you with the following points:
      CO2-EOR can play a key role in developing the 
infrastructure and the technical understanding to enable large scale 
CO2 sequestration in brine reservoirs.
      CO2-EOR combined with carbon capture from 
power plants and other stationary sources can have a significant 
positive impact on domestic oil production.
                                 ______
                                 
    Mr. Costa. Thank you, Professor Duncan. And I look forward 
to getting back to you with some questions.
    Our last witness with this panel is Mr. Mark Demchuk, is 
that right? Demchuk?
    Mr. Demchuk. Yes, it is.
    Mr. Costa. And you are the Team Leader with Weyburn of 
EnCana Oil and Gas Partnership.
    Mr. Demchuk. Yes.
    Mr. Costa. Did I get that all right?
    Mr. Demchuk. It is pretty close. Thank you, Mr. Chairman.
    Mr. Costa. You may begin your testimony.

 STATEMENT OF MARK DEMCHUK, TEAM LEAD, WEYBURN, ENCANA OIL AND 
                        GAS PARTNERSHIP

    Mr. Demchuk. My name is Mark Demchuk, and as you said, I am 
EnCana Corporation's Team Lead for our Weyburn CO2-
enhanced oil recovery project.
    EnCana is a North American industry leader in 
unconventional natural gas and integrated oil development. We 
have significant operations in the United States, including two 
refineries that we have in partnership with Conoco Phillips, 
one in Illinois and one in Texas.
    In 2007 our U.S. natural gas production from operations in 
Wyoming, Colorado, and Texas totaled 1.3 billion cubic feet per 
day. The Weyburn project is located in Saskatchewan, Canada, 
and is a technology-driven business that is both Canada's 
largest carbon dioxide-enhanced oil recovery project, as well 
as the world's largest CO2 geological storage 
project.
    I am currently responsible for all aspects of the Weyburn 
business, including strategy, business development, technology, 
drilling, operations, and stakeholder relations.
    Last year at a hearing here in May, one of my colleagues 
from EnCana also testified on the Weyburn project in front of 
the Subcommittee on Energy and Mineral Resources, and the 
Subcommittee on National Parks, Forests, and Public Lands. The 
hearing was titled ``Geological and Terrestrial Sequestration 
of CO2.'' So my testimony here today is very similar 
to what she provided last year.
    The geological storage of CO2 in oil zones 
offers a novel win-win approach to mitigating emissions, while 
enhancing production for mature oilfields. In Weyburn, 
CO2 has been injected one mile underground for the 
primary purpose of enhanced oil recovery since 2000, making 
valuable use of a byproduct that would have otherwise been 
emitted to the atmosphere from Dakota Gasification Company's 
coal gasification facility located in Beulah, North Dakota.
    Discovered 50 years ago, we now expect the economic 
producing life of the Weyburn oilfield to be extended up to an 
additional 30 years, through the use of CO2-enhanced 
oil recovery. We currently produce over 28,000 barrels per day, 
and the field is projected to store around 30 million metric 
tons of CO2 over the life of the project. This 
equates to taking about 6.7 million cars off the road for one 
year.
    At present, we inject about 125 million cubic feet a day of 
CO2 from Dakota Gas, and that has resulted in over 
10 million tons of CO2 storage since the project 
started in 2000.
    The Weyburn oilfield has also served as the highly coveted 
commercial-scale laboratory for the International Energy 
Agency's Greenhouse Gas Weyburn-Midale CO2 
Monitoring and Storage Project. The first phase of this multi-
party international research project, run under the auspices of 
the IEA, concluded in 2004 that storage of CO2 in an 
oilfield is viable and safe over the long term.
    Through extensive geological, geophysical, and 
hydrogeological work, as well as computer modeling, it 
concluded that after 5,000 years, 99.8 percent of the 
CO2 injected into the Weyburn field would remain 
trapped underground.
    Mr. Chairman, EnCana is proud of the Weyburn project. The 
project did not happen overnight. It took years of technical 
analysis, substantial capital investment, a viable 
CO2 supply, as well as lengthy, complicated 
negotiations with our partners, CO2 supplier, and 
governments. We believe that there are opportunities to conduct 
similar enhanced oil recovery and storage projects in other 
areas, and that deep geologic formations can be successfully 
used to store CO2.
    I must caution, however, that any project must be closely 
monitored, and there must be a sound scientific basis 
established to assure that the geologic formation being used is 
adequate to store CO2. That is why we continue to 
work closely with governments, researchers, and industry on the 
final phase of the IEA project to enable transfer of knowledge 
and technology gained in Weyburn to a more widespread 
industrial implementation.
    The IEA project is providing a good foundation for 
development of solid policy, regulations, and operating 
practices for future CO2 storage.
    I thank you for allowing me to come and testify today, and 
I would be glad to answer any questions you may have.
    [The prepared statement of Mr. Demchuk follows:]

             Statement of Mark Demchuk, Team Lead Weyburn, 
              EnCana Corporation, Calgary, Alberta, Canada

    My name is Mark Demchuk. I am Team Lead of the Weyburn Unit for 
EnCana Corporation. EnCana is a dynamic North American leader in the 
production of oil and gas. I am currently responsible for all aspects 
of the Weyburn Operation managing a staff of over 100 employees and 
contractors split between our Weyburn field site and in the Calgary 
head office.
    I am here today at the invitation of the Chairman to discuss 
EnCana's experience with carbon dioxide(CO2) enhanced oil 
recovery and the International Energy Agency's world-class research 
project at Weyburn centered on the geological storage of 
CO2.
Introduction
    The Weyburn oilfield, operated by EnCana, is demonstrating that oil 
production can be increased in an environmentally responsible manner 
through underground injection of CO2. CO2 has 
been injected into this oilfield since 2000, making valuable use of a 
by-product that would have otherwise been emitted from Dakota 
Gasification Company's (DGC) coal gasification facility located in the 
northern United States. The field is projected to store 30 million 
tonnes of CO2 over the EOR life, equal to taking about 6.7 
million cars off the road for one year. I will discuss in more depth 
how EOR is prolonging the life of the Weyburn oilfield, while at the 
same time contributing to reducing CO2 emissions.
    The Weyburn oilfield has also served as the highly coveted, 
commercial-scale laboratory for the International Energy Agency (IEA) 
Green House Gas Weyburn-Midale CO2 Monitoring and Storage 
Project. This multi-party, international research project, run under 
the auspices of the IEA, is investigating the viability of long term 
storage of CO2 in an oil reservoir and will provide a good 
foundation for the development of solid policy, regulations and 
operating practices for future CO2 storage associated with 
EOR. The results of the first phase of the IEA project will be covered 
as well as the key elements of the final phase, which was launched in 
2007.
EnCana Corporation--An Overview
    Headquartered in Calgary, Alberta, Canada, EnCana is a leading oil 
and gas producer in North America, where the company's primary focus is 
on the development of resource plays. EnCana's portfolio of long-life 
resource plays includes four key resource plays in the U.S. that 
produce natural gas. In Canada, five key resource plays produce natural 
gas and five focus on oil, one of which is the Weyburn property.
    In 2007, EnCana produced 3.6 billion cubic feet of natural gas per 
day from approximately 45,000 wells across North America, in addition 
to more than 134,000 barrels of oil and natural gas liquids per day. 
EnCana's U.S. natural gas production averaged 1.3 billion cubic feet 
per day in 2007.
    On May 11, 2008, EnCana Corporation's Board of Directors 
unanimously approved a proposal to split EnCana into two highly focused 
energy companies--one a natural gas company with an outstanding 
portfolio of early life, North American, natural gas resource plays and 
the other a fully integrated oil company with industry-leading in-situ 
oilsands properties and top-performing refineries, as well as an 
underlying foundation of reliable oil and gas resource plays. This 
transaction, which is expected to be completed in early 2009, is 
designed to create two highly sustainable, independent entities, each 
with an ability to pursue and achieve greater success by employing 
operational strategies best suited to its unique assets and business 
plans.
    EnCana strives to increase the net asset value of the company for 
shareholders, make efficient use of resources and minimize its 
environmental footprint. The company's success is determined not only 
through its bottom line but also through its behaviour. Weyburn is an 
example of that commitment
Weyburn Oilfield--Enhanced Oil Recovery
    Located in the southeast corner of the province of Saskatchewan in 
Western Canada, Weyburn is a 180-square-kilometer (70-square-mile) oil 
field discovered in 1954. It is part of the large Williston sedimentary 
basin, which straddles Canada and the U.S. Production is 25- to 34-
degree API medium gravity sour crude. The reservoir is a Mississippian-
aged Midale Marly zone, a low permeability chalky dolomite overlying 
the Midale Vuggy zone, a highly fractured and permeable limestone.
    Water-flooding to increase oil recovery was initiated in 1964 and 
significant field development, including the extensive use of 
horizontal wells, was begun in 1991. In September 2000, the first phase 
of a CO2 enhanced oil recovery scheme was initiated. The EOR 
project is to be expanded in phases to a total of 92 patterns over the 
next 15 years. The CO2 is a purchased byproduct from DGC's 
synthetic fuel plant in Beulah, North Dakota. If this CO2 
had not been used for EOR and stored, it would continue to have been 
emitted into the atmosphere. It is transported through a 200 mile 
pipeline to Weyburn then injected into the reservoir, one mile 
underground. The CO2 is 95% pure and Weyburn's current take 
is 6600 tonnes/day (equivalent to 125 mmscfd).
    Discovered 50 years ago, we now expect the economic producing life 
of the Weyburn oil field to be extended up to an additional 30 years 
through the use of CO2 enhanced oil recovery It currently 
produces over 28,000 bbls/d of light crude oil, the highest production 
level in 30 years. Without EOR, it is estimated that current production 
would have declined to 12,000-13,000 bbls/d leaving a huge resource 
untapped. The environmental benefits are also significant as 
CO2 storage contributes to mitigating emissions. The Weyburn 
project has stored approximately 10 million tonnes of CO2 to 
date and over the lifetime of the EOR project, it is projected that an 
additional 20 million tonnes of CO2 will be sequestered.
IEA Green House Gas Weyburn CO2 Monitoring & Storage 
        Project--Phase I
Project description
    The IEA Green House Gas Weyburn CO2 Monitoring & Storage 
Project is a significant CO2 monitoring and storage research 
and development effort that was run in parallel with the commercial 
Weyburn EOR project during 2000-2004. Phase 1 of this project was 
designed to contribute significantly to the understanding of greenhouse 
gas management, specifically the technical feasibility and long term 
fate/security of CO2 storage in geological formations.
    Initiated in 2000 by the Saskatchewan Ministry of Energy and Mines 
(now Saskatchewan Industry and Resources), the federal Department of 
Natural Resources, and PanCanadian Energy Corporation (now EnCana), the 
first $40 million phase of this multi-disciplinary project has been 
endorsed by the IEA GHG Research and Development Programme. It was 
managed by the Petroleum Technology Research Centre (PTRC) of 
Saskatchewan.
    This project constitutes the largest, full-scale, in-the-field 
scientific study ever conducted in the world involving carbon dioxide 
storage. Weyburn has become the international flagship project on GHG 
geological storage research, routinely receiving senior level business 
and government visitors, as well as media, from around the globe.
    The collaborative Phase One research was funded by 15 public and 
private sector institutions. In addition to the two previously 
mentioned government departments, other government partners included 
the United States Department of Energy (US DOE), the European Union, 
and the province of Alberta through the Alberta Energy Research 
Institute. Industry sponsors included EnCana, BP plc, ChevronTexaco 
Corp., DGC, Engineering Advancement Association of Japan, Nexen Inc., 
SaskPower, TransAlta Corporation and Total SA of France. The project 
also involved 24 research and consulting organizations in Canada, 
Europe and the United States.
    The overall objective of Phase 1 of the project was to predict and 
verify the ability of an oil reservoir to securely store and 
economically contain CO2. The scope of work focused on 
understanding the mechanisms of CO2 distribution and 
containment within the reservoir into which the CO2 is 
injected and the degree to which the CO2 can be permanently 
sequestered.
Phase 1 results 1
    Completed in 2004, Phase 1 concluded that CO2 can be 
securely stored underground in an oil reservoir such as Weyburn. 
Through extensive geological, geophysical and hydrogeological work, as 
well as initially simplistic deterministic and stochastic 
(probabilistic) performance assessment modeling, the work concluded 
that after 5000 years, 99.8% of the CO2 injected into the 
Weyburn field would remain trapped underground.
    A key feature of the project was the pre-injection baseline 
monitoring that was done prior to CO2 injection at the 
field. While there are already commercial applications of 
CO2 EOR in the United States, the Weyburn oilfield and the 
IEA GHG project are unique, due to the comprehensive knowledge of pre-
injection reservoir conditions as a result of an extensive historical 
database of geological and engineering information. This has proven 
critical to following the movement of CO2 in the Weyburn 
reservoir over the four years of the Phase 1 project and to the present 
day.
    Excellent monitoring techniques were demonstrated through the 
project; the movement of the CO2 was predicted, monitored 
and verified by a variety of different methods. The greatest success 
was encountered with four-dimensional time lapse seismic surveys, which 
can reliably detect relatively small volumes of CO2 
underground. Geochemical fluid sampling also gave good insights into 
the movement of CO2 within the reservoir and could detect 
any CO2 breakthrough at wells.
IEA Green House Gas Weyburn-Midale CO2 Monitoring & Storage 
        Project--Final Phase
    Phase 1 of the IEA project has provided a good foundation for the 
development of solid policy, regulations and operating practices for 
future CO2 storage/EOR projects; however, there is more work 
to be done. The Phase 1 final report identified a number of important 
gaps and recommended a follow-up ``Final Phase'' to build a technical 
Best Practices Manual that outlines geological storage site selection 
protocols, injection strategies, effective technologies for tracking 
CO2 through various geosciences technologies, completing and 
abandoning wellbores, and rigorous risk assessment strategies. Several 
gaps were identified at the end of the first phase of the project that 
will be addressed in the final phase project: understanding of the 
aging of wellbores over decades and centuries following abandonment, a 
credible peer-reviewed risk assessment approach, and a suite of cost-
effective long-term measurement and verification protocols to track 
CO2 movement underground. It was clear during the initial 
planning of the final phase project that information and advice could 
be provided to regulators for the development of advanced regulations 
based on incremental improvements of existing oil and gas regulations. 
Further, measurement, monitoring and verification (MMV) protocols would 
be identified during the project that would be valuable for crediting 
protocols. Governments and industry alike would derive benefits from 
completing the research at Weyburn through widespread knowledge and 
technology transfer. Demonstration of the integrity of geological 
storage at Weyburn would help to ensure public confidence in this 
greenhouse gas mitigation strategy through a proactive public 
communications and outreach program within the final phase project. The 
final phase of the project also includes the Apache Midale 
CO2-EOR operation that began CO2 injection in 
late 2006. We foresee a future where Weyburn has paved the way and 
future projects will not need to expend nearly as much research and 
monitoring resources to be assured of safe geological storage.
Next steps: Technical
    Extensive investment and effort have been expended to get to the 
current level of understanding of geological storage at Weyburn but 
additional work is still necessary to develop cost-effective protocols 
to enable efficient site selection, design, operation, risk assessment 
and monitoring of future projects.
    The key gaps identified in Phase I and the measures being taken in 
the Final Phase to address them and achieve win-win solutions include:
        (i)   Drafting of firm protocols for storage site selection.
        (ii)   Final selection of the most effective underground 
        monitoring methods for CO2 movements.
        (iii)  Identifying the most effective reservoir methods for 
        maximizing storage capacity and oil recovery.
        (iv)  Finalizing the development of the most cost-effective and 
        credible risk assessment methods and risk mitigation techniques 
        to ensure the integrity of the storage medium.
Next steps: Non-technical
    Advancement of the technical aspects of CO2 storage is a 
necessary but insufficient requirement for the management of geological 
storage of CO2 on a large scale. A successful CO2 
geologic storage ``industry'' must encompass a suite of technologies 
linked by a network of institutions, financial systems and regulations, 
along with public outreach activities, that are able to achieve broad 
public understanding and acceptance. Additional work is necessary in 
the following areas.
Regulatory Issues
    For CO2 storage to flourish, a predictable, science-
based regulatory regime needs to be in place. Fortunately, regulations 
governing the injection of acid gases with a CO2 component 
and other industrial applications are already in place. A complementary 
regulatory framework for long term storage applications with respect to 
safety and reliability may be required.
    The experience from current provincial regulations on issues such 
as emergency planning and protection, health and safety, and drilling 
and well completion standards, as well as the fact the oil has been 
kept in the geological structure for many years should prove very 
helpful to future CO2 storage regulatory efforts.
    Finally, a transparent registry system should be created, with 
well-defined measurement protocols and verification requirements, to 
ensure proper accounting for greenhouse gas reductions created by 
geological storage and recognition of offset credits.
Public outreach
    Geological Storage of CO2 is increasingly recognized as 
a pragmatic way to address CO2 emissions. An effective 
public outreach and consultation process could be helpful to ensure 
public understanding and acceptance of geological storage as a viable 
means of CO2 sequestration. The technology needs to be 
communicated to the public in the context of GHG mitigation options, 
with clear explanations regarding why it is safe and viable over the 
long-term.
Current Status--Final Phase
    The initial technical research package was approved by the sponsors 
in November 2006 along with a first year budget of $2.9 million 
(Canadian). Several research agreements are in place with research 
activities underway2. A number of agreements are pending execution. The 
technical research program is being expanded in a carefully managed and 
stage-gated process to ensure that results are directly applicable to 
the needs of a comprehensive Best Practices Manual, regulatory and 
policy advice and public outreach activities. Final phase project 
activities are integrated by four theme leaders in: geological 
characterization, wellbore assessment, geophysical and geochemical 
CO2 tracking, and risk assessment. Semi-annual coordination 
meetings are held with all researchers and sponsors to ensure 
dissemination of information and research prioritization on a 
continuous basis. International interest in this research project 
remains strong with new industry sponsorship coming from Apache Canada, 
Saudi Aramco, OMV Austria and Schlumberger. Sponsorship from the public 
sector remains strong from U.S. Department of Energy (NETL), and the 
Governments of Canada, Saskatchewan and Alberta. The project continues 
to be endorsed by the IEA Greenhouse Gas R&D Programme, with further 
endorsement coming from the Carbon Sequestration Leadership Forum since 
2004.
Conclusion
    It is EnCana's hope that the experience at Weyburn will enable the 
start-up of a significant number of commercial-scale EOR-based 
CO2 geological storage projects, a win-win scenario for the 
economy and the environment. These projects would provide substantial 
environmental benefits by enabling the geological storage of 
significant quantities of CO2 that would otherwise be 
emitted to the atmosphere. Ramping up development of CO2-
based EOR projects would also increase oil recovery and hence improve 
energy security. Conventional methods in North America may only recover 
approximately 30% of oil in place, leaving a tremendous resource in the 
ground for EOR.
    Although EnCana's activities have focused on EOR-based operations 
and not on other storage alternatives such as deep saline aquifers or 
coal bed methane, many of the operating practices so developed would be 
applicable to these other storage alternatives. Furthermore, the 
operating practices developed for Weyburn's geological environment 
would also be transferable to other sites with different geological 
characteristics. EOR projects currently represent the storage 
alternative that is the closest to being economic and with the right 
policy and regulatory framework, market signals and economic 
conditions, a number of projects could realistically be initiated.
    Finally, Weyburn, particularly the IEA GHG Project, demonstrates 
the power of collaboration and partnerships between governments, 
researchers and industry to unlock value through technology. The 
research was valuable to EnCana as it helped the company to better 
understand its oil field and to innovate (e.g. CO2 
monitoring by four-dimensional seismic survey). It provided the 
opportunity for a Canadian research centre to develop expertise and 
potentially become a world leader in CO2 geological storage 
monitoring and assessment. Finally, it has enabled government to 
advance their innovation, technology and sustainability agendas.
References
    1.  Wilson M. and Monea M., IEA GHG Weyburn CO2 
monitoring & storage project--Summary report 2000-2004, 7th 
International Conference on Greenhouse Gas Control Technologies, 
Vancouver, Canada, Sept. 5-9, 2004.
    2.  Knudsen, R. and Preston, C.K., Update of the IEA GHG Weyburn-
Midale CO2 Monitoring and Storage Project--Final Phase, 7th 
Annual Conference on Carbon Capture and Sequestration, Pittsburgh, PA, 
USA, May 5-8, 2008.

    1 ADVISORY ON FUTURE-ORIENTED INFORMATION: In the 
interest of providing EnCana Corporation (``EnCana'' or the 
``Company'') shareholders and potential investors with information 
regarding the Company and its subsidiaries and the proposed transaction 
to form GasCo and IOCo and management's assessment of the Company's 
future plans and operations, certain statements or information in this 
document contain ``forward-looking statements'' within the meaning of 
the United States Private Securities Litigation Reform Act of 1995 or 
``forward-looking information'' within the meaning of applicable 
Canadian securities legislation. Forward-looking statements or 
information in this document include, but are not limited to, 
statements with respect to: the future production potential and 
ultimate recoveries from the Weyburn project; the amount of 
CO2 which may be injected at Weyburn; the projected quantity 
of incremental production resulting from CO2 injection and 
projections for geologic storage of CO2 at Weyburn and the 
potential efficacy of CO2 sequestration on climate change; 
the ability of the Company to realize the long-term opportunity to 
undertake large-scale carbon capture and storage; the proposed 
transaction to form GasCo and IOCo and expected future attributes of 
each of GasCo and IOCo following such transaction; and the anticipated 
benefits of the transaction.
    You are cautioned not to place undue reliance on forward-looking 
information, as there can be no assurance that the plans, intentions or 
expectations upon which it is based will occur. By its nature, forward-
looking information involves numerous assumptions, known and unknown 
risks and uncertainties, both general and specific, that contribute to 
the possibility that the predictions, forecasts, projections and other 
forward-looking statements will not occur. Although the Company 
believes that the expectations represented by such forward-looking 
statements are reasonable, there can be no assurance that such 
expectations will prove to be correct. Some of the risks and other 
factors which could cause results to differ materially from those 
expressed in the forward-looking statements contained in these 
responses include, but are not limited to: volatility of and 
assumptions regarding crude oil and natural gas prices, assumptions 
based upon the Company's current guidance, fluctuations in currency and 
interest rates, product supply and demand, market competition, risks 
inherent in the Company's North American and foreign oil and gas and 
midstream operations, risks inherent in the Company's marketing 
operations, including credit risks, imprecision of reserves estimates 
and estimates of recoverable quantities of oil, bitumen, natural gas 
and liquids from resource plays and other sources not currently 
classified as proved reserves, the ability of the Company and 
ConocoPhillips to successfully manage and operate the North American 
integrated heavy oil business and the ability of the parties to obtain 
necessary regulatory approvals, refining and marketing margins, 
potential disruption or unexpected technical difficulties in developing 
new products and manufacturing processes, potential failure of new 
products to achieve acceptance in the market, unexpected cost increases 
or technical difficulties in constructing or modifying manufacturing or 
refining facilities, unexpected difficulties in manufacturing, 
transporting or refining synthetic crude oil, risks associated with 
technology and the application thereof to the business of GasCo and 
IOCo; the Company's ability to replace and expand oil and gas reserves, 
the Company's ability to either generate sufficient cash flow from 
operations to meet its current and future obligations or obtain 
external sources of debt and equity capital, general economic and 
business conditions, the Company's ability to enter into or renew 
leases, the timing and costs of well and pipeline construction, the 
Company's ability to make capital investments and the amounts of 
capital investments, imprecision in estimating the timing, costs and 
levels of production and drilling, the results of exploration and 
development drilling, imprecision in estimates of future production 
capacity, the Company's ability to secure adequate product 
transportation, uncertainty in the amounts and timing of royalty 
payments, imprecision in estimates of product sales, changes in 
royalty, tax, environmental and other laws or regulations or the 
interpretations of such laws or regulations, political and economic 
conditions in the countries in which the Company operates, the risk of 
war, hostilities, civil insurrection and instability affecting 
countries in which the Company operates and terrorist threats, risks 
associated with existing and potential future lawsuits and regulatory 
actions brought against the Company, and such other risks and 
uncertainties described from time to time in the Company's reports and 
filings with the Canadian securities authorities and the United States 
Securities and Exchange Commission. Accordingly, the Company cautions 
that events or circumstances could cause actual results to differ 
materially from those predicted. Statements relating to ``reserves'' or 
``resources'' or ``resource potential'' are deemed to be forward-
looking statements, as they involve the implied assessment, based on 
certain estimates and assumptions that the resources and reserves and 
resource potential described exist in the quantities predicted or 
estimated, and can be profitably produced in the future. You are 
cautioned that the foregoing list of important factors is not 
exhaustive. You are further cautioned not to place undue reliance on 
forward-looking statements contained in these responses, which are made 
as of the date hereof, and, except as required by law, the Company 
undertakes no obligation to update publicly or revise any forward-
looking information, whether as a result of new information, future 
events or otherwise. The forward-looking statements contained in these 
responses are expressly qualified by this cautionary statement.
                                 ______
                                 

    Response to questions submitted for the record by Mark Demchuk, 
                        Team Lead, Weyburn Unit

 Mr. Demchuk, when the firm protocols for storage site selection are 
        drafted, will those be just for fields where enhanced oil 
        recovery is taking place, or will they be broadly applicable?
Response:
    We (EnCana) believe that the protocols will be most relevant to 
enhanced oil recovery applications. However, there will likely be some 
relevance to other storage technologies, but how applicable remains to 
be seen.
                                 ______
                                 
    Mr. Costa. Thank you very much, Mr. Demchuk. For those of 
you who are focused on when we may have to recess, we are told 
votes will be between 11:15 and 11:30. So I suspect they will 
be any time here in the next 10 minutes. We will try and see 
how far we can go on the Q and A round prior to that. We 
usually have 15 minutes-plus when the first roll call is 
required.
    So let us begin. Mr. Demchuk, you mentioned that the 
extensive pre-injection baseline monitoring and time-lapse 
seismic studies at Weyburn, and Weyburn obviously is a model 
that we are all looking at. Will it be necessary to include 
those at other EOR sites? And are there other methods for 
monitoring the carbon dioxide that may not be as costly or take 
as long?
    Mr. Demchuk. Well, certainly we have enjoyed and used with 
great success 3-D seismic, and now 4-D seismic technology to, 
first of all, baseline the reservoir conditions, and then map 
and track the movement of CO2 within the reservoir 
since we started injecting.
    Just to distinguish the difference between 3-D and 4-D 
seismic, 4-D really means time-stamped. So you take a three-
dimensional seismic picture, and you are able to time-stamp it 
and follow the movement of CO2 within the reservoir.
    Mr. Costa. So as you apply that 4-D in future efforts, does 
it make them less costly?
    Mr. Demchuk. No, price doesn't really change. We spend 
about $2 million a year redoing the same seismic shoot to track 
the movements of the CO2 within the reservoir.
    Mr. Costa. At the end of the day, does the Weyburn project 
end up storing more carbon dioxide per barrel of oil than 
produced in other enhanced oil recovery projects?
    Mr. Demchuk. Well, I can't really say that we are going to 
store more CO2 per barrel of oil produced. We do 
anticipate that at the end of the useful life of the EOR 
project, we will continue to be able to store CO2 as 
a straight-up CO2 storage project.
    Mr. Costa. Mr. Duncan, short of putting a price on carbon, 
are there specific actions you think the government should take 
to really kick-start this storage effort for industrial carbon 
dioxide through EOR?
    Mr. Duncan. Well, I think solving the cost discrepancy that 
Tracy Evans referred to, I think the other thing that we can do 
is an active research program.
    The understanding that we have of CO2 EOR in the 
Permian Basin doesn't help us a lot once we move outside the 
Permian Basin, because the geological characteristics of the 
oil reservoirs are quite different. So we are going to have to 
have different approaches if we want to maximize oil recovery.
    Mr. Costa. One size doesn't fit all.
    Mr. Duncan. Exactly.
    Mr. Costa. Have you had a chance to look at any of the cap-
and-trade proposals that have been kind of percolating around 
here?
    Mr. Duncan. To tell you the truth, cap-and-trade proposals 
make my head hurt.
    Mr. Costa. I am glad I am not the only one.
    Mr. Duncan. So I try to avoid that activity.
    Mr. Costa. All right, all right. What is your take on 
whether or not this issue is, as carbon dioxide is defined, as 
a waste or a commodity?
    Mr. Duncan. It is an issue that I don't find terribly 
exciting. I think the important thing is that we clear the way 
to increasing CO2 EOR. I don't find those kind of 
legal nitpickings particularly exciting.
    I think if there is clear legislation on the Federal level, 
that it will clear away any uncertainties related to 
terminology and semantics.
    Mr. Costa. This question is for everyone on the panel, and 
you will have to be brief because my time is going.
    The Department of Interior recently concluded tax policies 
and grants focused on research and development. Some of you 
indicated in your testimony that in terms of enhanced oil 
recovery, it would be more effective in terms of royalty 
relief. Do you agree with that? And can anyone tell me what you 
think the current price of carbon dioxide is, and how closely 
that is related to the price of oil?
    Mr. Roby, let us begin with yourself.
    Mr. Roby. We have various pricing for CO2 based 
on the long-term contracts that we have had. Some do slide with 
the price of oil. So yes, the price of CO2 is a 
function of oil price.
    Mr. Costa. And in terms of royalty relief for produced oil?
    Mr. Roby. Would you repeat the question, Chairman?
    Mr. Costa. The conclusion that tax policies and grants, and 
I think you said it in your statement, you would rather have 
royalty relief than grants. Is that correct?
    Mr. Roby. Right, right. As you know, CO2 
projects are a long-term project. The price of oil is certainly 
an uncertainty. We would like to be able to put as much 
certainty in there as we could. Royalty relief we think would 
be helpful.
    Mr. Costa. Yes. Quickly, since everything is local, you 
have a plant in my area that you are developing, Occidental is, 
for enhanced oil recovery. Could you tell us more about that 
project?
    Mr. Roby. Well, we are in negotiations, and there is 
ongoing discussions for a plant out there. It is just in the 
discussion stage; things are being negotiated and talked about. 
There has been a public release by the parties involved in it.
    We are talking to other companies, as well, so that is just 
one of several that we are just in the talk----
    Mr. Costa. I will get additional information from you later 
on. My time has expired, and therefore so has everybody else's. 
But we will get to a second round here, because we have I think 
a lot of questions.
    The gentleman from New Mexico, the Ranking Member, Mr. 
Pearce.
    Mr. Pearce. Thank you, Mr. Chairman.
    Mr. Costa. And after, I think, when you complete your 
questions, we will probably have to go and vote. I assume the 
roll call has started?
    OK. Go ahead, Mr. Pearce.
    Mr. Pearce. Mr. Roby, on the whole idea of using 
CO2 as sequestration, is this an activity that a 
startup firm could be involved in? In other words, I am trying 
to get an idea of the magnitude of experience necessary. So 
could we just say a power company built a plant, and then start 
pumping CO2 down in the ground right there where it 
is?
    Give me just a brief answer about that.
    Mr. Roby. As you know, it is very complex. It is very 
costly. Injecting CO2 in the ground takes huge 
economic analysis.
    And so to answer your question, I would say no, it is not 
for a small startup company. It takes a company with a long-
term perspective. It is costly, and, you know, with it being 
costly, it does take experts to understand the implications of 
where the CO2 is going, the correct monitoring, and 
the correct processing.
    Mr. Pearce. We will have the staff hold the chart up here. 
What I am saying here is there is some field there, looks like 
in west Texas, eastern New Mexico, where I live and we made, 
our business was there. So I am seeing a curve, the green 
curves show the amount of oil that comes. But I am seeing 
constant, constant redrilling and then in-in-filling of the 
field to create that high peak of oil that we get.
    But then we see that the oil that is retrieved against the 
decline out here. Where we put the red graph on, that is where 
you begin to inject and do more in-filling. And so the only way 
we are able to extend the life of that field is through this 
enhanced oil recovery. But that enhanced oil recovery is, 
percentage-wise, still a very kind of small portion of the 
total field. Is that a correct----
    Mr. Roby. That is correct. In fact, that appears to be for 
the entire Permian Basin. And that is right. It looks like we 
have all water flood primary and secondary recovery there.
    And the CO2 recovery, though it is extremely 
valuable to extend the reserves, it is, just makes a small 
percentage. We talked about today 15 percent recovery. So most 
of the recovery is going to be from primary and secondary.
    This is, it is not a silver bullet. It is helpful, but it 
will not solve all the problems that we have with energy.
    Mr. Pearce. Now, I have heard speculation that there is 
currently legislation that is being drafted to just shut off 
the natural sources of CO2. What effects would that 
have on this field, and employment, the output, if we had 
legislation that just stopped the natural-occurring sources of 
CO2?
    Mr. Roby. It would be devastating. In short, CO2 
production is significant in the Permian Basin. There is quite 
a bit looking in other parts of the country. If we shut down 
using natural-occurring CO2, as talked about with 
the immature capturing CO2 from industrial 
locations, and without the infrastructure, we would shut down a 
tremendous amount of oil production in the United States. And 
unemployment would be significant in your home state, as well 
as west Texas.
    Mr. Pearce. Mr. Demchuk, your observations on the same 
issue.
    Mr. Demchuk. Well, from a production perspective, I didn't 
bring it, but I have a very similar chart that shows the 
production of the Weyburn field, which is 50 years old. And, as 
Mr. Roby described, the bulk of our production will have come 
from primary production and water flood, and we are simply 
extending the life of the field and increasing our production 
in the neighborhood of about----
    Mr. Pearce. So if we lost the source of naturally occurring 
CO2 and mandated only carbon sequestration sources.
    Mr. Demchuk. Well, actually, for us it would make no 
difference, because we use manmade CO2 from a coal 
gasification facility.
    Mr. Pearce. And even in your U.S. operation--you have U.S. 
operations?
    Mr. Demchuk. Not on the EOR side of the business. Our U.S. 
operations are primarily gas production.
    Mr. Pearce. Mr. Duncan, do you have any idea about how long 
it would be before we really are able to seriously harvest 
CO2 in the United States for enhanced oil recovery? 
Just a number of years. Just a guess is fine.
    Mr. Duncan. Well, I can give you more than a guess. If you 
started a project now, probably five to seven years to build 
capture plans. And I asked some people in Kinder Morgan how 
long they thought it would take to bring in, and they said four 
to seven years, so that is sort of consistent.
    Mr. Pearce. OK. Mr. Chairman, I see my time has elapsed. I 
have more questions. We will wait until the second round, and I 
know we have to go. Thanks.
    Mr. Costa. Thank you very much, Mr. Pearce. I would advise 
those on the second panel and those in the audience, we will be 
gone for at least half an hour. So my best guess is that we 
will begin probably some time after 12:10, 12:15. So if you 
have an opportunity, want to get a cup of coffee or use the 
facilities, or whatever.
    But I know there is interest by the gentleman from New 
Mexico and myself, and we will have a second round of 
questions. And so we will see you in about half an hour. Thank 
you.
    The Subcommittee is now in recess.
    [Recess.]
    Mr. Costa. All right. I think we have our panel back. It 
took a little longer than we had anticipated. I apologize for 
that. But we are going to try to get in another round here with 
the members that are here, and we will bring this to a close.
    I think we ended with the gentleman from New Mexico, Mr. 
Pearce's questioning, and so I will start off here on the 
second round.
    Mr. Evans, what are you doing that is feasible offshore? We 
know that production rates have declined, especially on the 
shallower wells offshore of the Gulf. So could this technique 
be used there?
    Mr. Evans. Mr. Chairman, Denbury is currently not doing 
anything offshore, but there is no technical reasons why you 
can't do CO2 EOR offshore. It becomes more of an 
economic issue of taking the CO2 offshore. And 
generally in the offshore environment, the costs just go up to 
do the same thing that you are doing onshore.
    But there is no technical reason why you can't do 
CO2 EOR offshore.
    Mr. Costa. You talked about, and Mr. Pearce pointed out the 
issue with the pipelines, and we understand that access is 
important, if there was a change in the tax code that would 
provide incentives, do you think there would be much investment 
in the private sector to deal with the pipeline, the 
transmission capacity?
    Mr. Evans. I think there would be a great deal of interest 
in building more pipelines for CO2. Most of your 
pipeline operators, what they want to really have assurance of 
is that there is going to be throughput through that pipeline.
    So not only would it encourage investment, but it would 
also lower the total cost of, delivery cost of anthropogenic or 
manmade CO2, as well.
    Mr. Costa. You also mentioned, I guess, in your comments 
about the tax credit for the CO2 EOR that was almost 
enacted last year. Do you think that is enough to incentify the 
construction for pipelines?
    Mr. Evans. Well, the tax credit actually is for the capture 
of the CO2, not necessarily the pipelines. The issue 
that we see is, as Denbury is, the actual oil and gas companies 
can build or pay for, in terms of CO2 costs, most of 
the pipeline infrastructure. And we can only cover a portion of 
the capture costs, depending on which source it is coming from.
    Obviously the lowest capture cost we believe is future 
gasification projects. And as you go up from there, then we can 
only cover a lesser and lesser amount.
    Mr. Costa. OK. Mr. Roby, and I guess maybe Mr. Evans, do 
either of your companies have plans for converting your fields 
to storage at the end of the EOR operations? And what would be 
the legal or regulatory or financial impediments if you did so?
    Let me start with Mr. Roby.
    Mr. Roby. As far as plans, we don't have plans at this 
point in time. However, we do recognize that after we inject 
quite a bit of CO2 in these fields, that the 
CO2 will stay there. So the natural process does 
store CO2.
    We also recognize that CO2 is quite a commodity. 
And if we can take that CO2 in a field that has used 
it, and we depleted the oil resource from that field, we would 
then take it to another field.
    So since we have invested tremendous millions of dollars 
for the CO2, we are going to try to have that 
contacting as much oil as possible.
    Mr. Costa. Well, with that statement made, where do you see 
this EOR effort going in the next 10 or 20 years from 
Occidental's perspective?
    Mr. Roby. We are excited about CO2 flooding, as 
we have been in the past. We want to continue to grow it. We 
want to continue to put CO2 flooding in the Permian 
Basin.
    As you know, we have looked at other areas of the country, 
and we are currently investigating that. We hope that it will 
grow into other regions beyond the Permian Basin. And in the 
fields that have not been taking CO2 we are 
continually growing that, and we plan to continue to do so.
    Mr. Costa. Mr. Evans?
    Mr. Evans. We don't currently have that necessarily in our 
business model. We are going to also continue to expand. We are 
planning now with the three contracts to take anthropogenic 
volumes of CO2, so we are going to sequester through 
EOR. But taking those fields beyond the EOR, we have not put 
that in our business model.
    We are aware that a lot of our oilfields are sitting right 
in amongst saline reservoirs, as well, and so we are cognizant 
of that. And we fully expect our pipelines, once EOR is over, 
to be able to be utilized for the transportation of manmade for 
storage.
    The second part of your question was the impediments. I 
think the biggest impediment right now is determining legally 
who owns the pore space.
    Mr. Costa. Who owns the----
    Mr. Evans. The pore space, where the CO2 will be 
captured. There is no clarity on that issue yet. I know several 
states have been working on that, and right now they are not 
necessarily in agreement, either. So that is probably the 
biggest impediment. Access to land, and then who owns that pore 
space.
    Mr. Costa. Dr. Kunkel, you mentioned you effectively need a 
cap-and-trade system to make your project economic. Is there a 
price for carbon dioxide that would make it economic? Or would 
you say there is another way of partnering with oil producers?
    Mr. Kunkel. Well, a price for carbon dioxide is necessary. 
You know, the exact price also depends on a lot of other 
varying commodity prices, such as electricity market prices in 
Texas, coal price, and so on.
    But if there was a market price of CO2 emission 
reduction of $20 to $25, it would start to look very good for 
us.
    Mr. Costa. OK, my time has expired. The gentleman from New 
Mexico, Mr. Pearce.
    Oh, I am sorry.
    Mr. Sali. Mr. Chairman, you missed me on the first round.
    Mr. Costa. No, I know, and I am going to do my mea culpas 
right now.
    Mr. Sali. How would you like to handle that? I can take 10 
minutes on the second round, or I can go now and take up my 
first round.
    Mr. Costa. Why don't we alternate, Mr. Scalise? I am sorry, 
Mr. Sali.
    Mr. Sali. You want me to go now? I am sorry.
    Mr. Costa. Yes.
    Mr. Sali. OK. Mr. Roby, you mentioned in your testimony I 
think that Occidental has been involved in enhanced oil 
recovery for 30 years. In addition to carbon dioxide injection, 
what other types of enhanced oil recovery has your company been 
using?
    Mr. Roby. We were active in steam flooding in the United 
States, and also in the Mid-East. We are currently putting in 
those first large commercial steam flood in the Mid-East; it is 
a very large project in Oman.
    We are also looking at chemical flooding in the domestic 
arena, both in Texas and California, as well as we are looking 
in Latin America and in the Mid-East. So we are actually active 
in EOR projects in the three areas that we operate, which is 
Mid-East, North Africa, Latin America, and the United States.
    Mr. Sali. Now, with respect to the total enhanced oil 
recovery efforts that your company is involved in, what 
percentage of that is from carbon dioxide injection? Just 
approximately.
    Mr. Roby. A third. It is about--no, that is too high. It is 
about 20 percent for CO2.
    Mr. Sali. Is it fair to say that you anticipate this will 
be a growing area? Or other types of enhanced oil recovery 
would grow with that? Or what do you see for the future?
    Mr. Roby. We see it as growth. Will it grow on a percentage 
basis on CO2? I am unsure about that, because we 
want to grow in other areas where we are not putting in 
CO2 floods.
    I will tell you that we are looking at putting in 
CO2 floods in other continents, as well. But we do 
believe ultimate production will grow through CO2.
    Mr. Sali. As we look, I am reminded of the chart that was 
shown a little earlier. It looks like in the Permian Basin, 
there is a declining amount of recovery that is going to come 
from that basin, total recovery.
    Mr. Roby. Right. Yes, sir.
    Mr. Sali. When we talk about enhanced oil recovery using 
CO2 injection, what percentage of the total crude 
oil needs for the United States will that produce?
    Mr. Roby. Well, let me quantify. CO2 production 
in the Permian Basin is in the tune of about 200,000 barrels a 
day. And I believe your question is what percent of that is the 
total domestic production?
    Mr. Sali. I am actually looking at the feasibility of 
carbon dioxide injection and the recovery that we will get from 
that, not just from your company, but other companies. Do you 
have any kind of a guess about what percentage of our energy 
needs going forward we can rely on from this?
    Mr. Roby. In opening comments by the Chairman, it was said 
that there is no silver bullet. I agree with that completely.
    This will help. I believe that we can, you can hope to get 
in the tune of 15 percent to 20 percent recovery from 
CO2. There is, by no means every reservoir is 
capable of producing CO2. I do believe that there is 
many reservoirs in the Gulf of Mexico that aren't floodable by 
CO2, just due to gravity override. The permeability 
and the precocity is such that the testing that has been done 
in some areas shows that CO2 will actually rise to 
the top, so in fact it was not a very good formation for 
producing CO2, or for using CO2 to 
produce.
    So as a result of that, I think it is a little helpful, but 
in the tune of--and this is an educated estimate--a small 
percent, let us say 10 percent, in that tune.
    Mr. Sali. You think that we could have as much as 10 
percent of the total production for the United States----
    Mr. Roby. Oh, no. Oh, no, not in total. What I mean is that 
if you look at floodable areas, you could potentially recover 
10 percent. But if you look at that in the, in total of 
floodable fields, it is a smaller percent than that. Because 
again, there is many fields that you can't put CO2 
in; it is just not amenable to this process.
    Mr. Sali. Here is what I am trying to get at. If we are 
going to look forward and meet the energy needs of this 
country, to what extent can we rely on CO2 
injection? To what extent are we going to have to rely on new 
production exploration to give us new production in areas where 
we aren't today? How does this fit in that puzzle?
    Mr. Roby. We are going to have to have new primary 
production and water flood production. There is no question 
about that. CO2 will help, but again, it is not 
going to be the savior. It is going to help.
    Quantification, we have 200,000 in today. You could double 
that, say 400,000, wildly. That is still just 10 percent of 
total production in the United States. But clearly below what 
our consumption is.
    Mr. Sali. Thank you. Thank you, Mr. Chairman.
    Mr. Costa. I thank the gentleman from Idaho. And again, I 
was not intentioned to avoid your time there.
    Mr. Sali. That is fine.
    Mr. Costa. I try to be fair.
    Mr. Sali. All right.
    Mr. Costa. Mr. Evans, what kind of plants are you getting 
your industrial carbon dioxide from?
    Mr. Evans. We plan to get it from three basic plants. One 
is a coal-to-liquids plant, one is a pepcoke-to-ammonia plant, 
and the other is more than likely going to be pepcoke to a 
combination of ammonia and methiodal.
    Mr. Costa. How much more expensive is the natural gas than 
the carbon dioxide pipeline?
    Mr. Evans. How much is the manmade CO2, or 
natural gas?
    Mr. Costa. How much more expensive is natural gas?
    Mr. Evans. Well, natural gas is about $12 per NCF. You 
know, manmade CO2 is probably going to be in the 
neighborhood of, you know, depending on negotiations, somewhere 
between a dollar and two dollars.
    Are you talking about natural CO2?
    Mr. Costa. Yes. I am sorry, I don't think I was clear on my 
question. I am talking about the price of the pipeline.
    Mr. Evans. Oh, the price of the pipeline? Oh. On a per-inch 
mile, generally the prices won't be that much different on the 
pipelines. The big difference between pipelines is we have a 
heavier grade of steel, because we generally operate 
CO2 at 2200 psi or greater, where a natural gas 
pipeline would be 1200.
    So what you would see is a slightly higher price for the 
actual pipe, but the construction would be closer than that. My 
best estimate would be probably in the neighborhood of 15 
percent to 20 percent more.
    Mr. Costa. OK. Dr. Kunkel, are you working closely with the 
Department of Energy on attempting to, with the new plan, I 
think we had a description in your submitted testimony, in 
terms of funding for the captured portion of the plant you 
described?
    Mr. Kunkel. We have submitted information about our project 
in response to the recent information request that they have 
about various carbon-capture and gasification types of 
projects. And so they have our information; they know of our 
interests, and we are aware of their interests. They have a 
process going forward which may take some time.
    Mr. Costa. Will you still build your plant if you don't 
have the capture piece?
    Mr. Kunkel. We do not intend to build a plant without the 
capture piece. We see it as, you know, part and parcel of this 
project.
    Mr. Costa. All right. Professor, you clearly have been in 
the field for a number of years. Where do you see this all 
going in terms of the potential? I mean, we are trying to 
combine challenges here that we have with CO2 
levels, we are trying to obviously enhance our oil and gas 
recovery. We are in an energy crisis. I think a number of us 
have made the comment that there is no silver bullet. I think 
that is true, there is no silver bullet.
    I guess the policy debate we are having here in Washington 
is what is the proper mix between additional domestic sources, 
both onshore and offshore, enhancing our older fields, and 
dealing with other alternative forms of energy.
    Where do you, in terms of your focus, where do you stand 
down there at Texas University?
    Mr. Duncan. In terms of my personal focus, I agree with Mr. 
Roby about the fact that CO2 EOR is not going to 
have a huge impact on domestic oil production. It can have a 
very meaningful impact, but it is not going to turn the ship 
around.
    However, it can have a meaningful, a really meaningful 
impact in terms of CO2 sequestration. It can play a 
significant role. It can also play a very significant role in 
developing the infrastructure that can later be used for brine 
sequestration.
    Mr. Costa. The infrastructure part I get. But in terms of 
the significant role of the capture, how do you describe a 
significant impact? I mean, what in your mind constitutes, I 
guess, a significant impact?
    Mr. Duncan. Well, I think a significant impact would be if 
you look at the Princeton people's wedge idea of tackling the 
CO2 problem, if you could capture 10 percent of the 
CO2, or 20 percent say in the Gulf Coast and the 
other oil-producing areas as susceptible for CO2 
EOR, I think that would be a big chunk of a U.S. contribution 
toward a carbon-constrained world.
    Mr. Costa. And then that technology would be applicable in 
other parts of the world.
    Mr. Duncan. Exactly, yes. As a matter of fact, if 
CO2 sequestration is going to occur anywhere in the 
world, it is basically going to take place with technology 
developed in the U.S., in the Gulf Coast, in Texas. And it is 
going to require expertise from those people who have been 
doing CO2 injections for the past 35 years or so.
    Mr. Costa. And we have the expertise here.
    Mr. Duncan. We have the expertise. We have the knowledge, 
we have the understanding. We need more of it, but we have a 
lot of it.
    Mr. Costa. All right. My time has expired. The gentleman 
from New Mexico, Mr. Pearce.
    Mr. Pearce. Thank you, Mr. Chairman. Mr. Roby, how much 
would the price of gas go up, gasoline at the pump go up if we 
were to shut off naturally occurring sources of CO2 
today? And I worry about that. I listened with extreme concern 
as Maxine Waters described the process where the government 
might take over and run the oil companies. And so I really have 
great fears about what the intent of the majority is.
    So what would be the cost? What would happen to the price 
of gasoline, in your estimation?
    Mr. Roby. Well, Occidental is not in the refining and 
marketing business, so we have no, so we don't have an arm of 
that.
    However, you mentioned in my estimation. I just know that 
the price is a function of supply and demand of the base 
product, and the supply of crude would go down. As I mentioned 
early in my remarks, I believe not using naturally occurring 
CO2 would be devastating. And we could easily pull 
out 200,000 barrels a day from the Permian Basin, and potential 
growth beyond this.
    So all I can tell you is directionally, it would go up. And 
I think it would certainly not be good for the energy of this 
country.
    Mr. Pearce. You have heard Mr. Evans's optimistic view 
about the investment that would be attracted by the, toward the 
building of pipelines. Do you anticipate that the building of 
any carbon dioxide-transmitting pipelines might be met with 
protests and with litigation?
    Yesterday I think one of the Circuit Courts handed down a 
decision that a refinery can't be built, so again we have made 
another decision not to build refineries in this country 
yesterday. Do you think there would be any objections by groups 
that don't want these pipelines built?
    Mr. Roby. There will always--yes.
    Mr. Pearce. Yes. And how far along would you think that we, 
to get a series of pipelines across the country that would feed 
all of the, all of the fields that are hospitable to 
CO2 injection, would you take a guess at how long it 
would take to get all that infrastructure through the courts 
and through the processes?
    Mr. Roby. It would be enormous. It has taken us decades to 
get to where we are today with natural gas. Permitting process 
is taking longer today than it was a decade ago.
    I would venture to speculate that we are looking at 20-ish 
years.
    Mr. Pearce. Twenty years. Mr. Evans, would that dampen down 
the enthusiasm, all these people lined up to build these 
pipelines? Do you think they will keep their money on the 
docket for 20 years while they are waiting for the process?
    Mr. Roby. Well, I think, of course, we will----
    Mr. Pearce. I am asking Mr. Evans. Excuse me.
    Mr. Evans. Well, I think in order to build, you know, 
500,000 miles in infrastructure, you say that would take 20 
years. Individual pipelines in all producing regions, we don't 
see a lot of protests. We have not seen----
    Mr. Pearce. OK, but we are talking about building 
infrastructure across the entire country. And we are talking 
about significantly affecting the CO2 that is 
available. And so yes, I know your situation is just from 
Sweetwater to the field.
    Mr. Evans. Right.
    Mr. Pearce. But I am asking a generalized question.
    Mr. Evans. Well, yes. People will invest in these pipelines 
as long as they are assured that they are going to be able to 
get put in.
    Mr. Pearce. Yes, they are not going to leave their money 
sitting on the table.
    Mr. Evans. Well, it won't be sitting on the table. It took 
almost 50 years to build the infrastructure we have today, but 
that is built out as you build volume.
    So yes, we will face protests. We may or may not need 
eminent domain. But those kind of things can all be addressed.
    Mr. Pearce. And by the way, we just had a hearing here a 
couple weeks ago where people are protesting the corridors; we 
set up corridors in the 2005 Energy Policy Act to convey 
different forms of energy. And the protests are occurring that 
will probably stop that entire project. So I am just trying to 
keep our feet on the ground here, as we look with enthusiasm.
    Mr. Evans, let us say that we do withdraw the naturally 
occurring sources of CO2, and we see, say, a five-
time increase in the price of carbon, would your company still 
do a CO2 injection with a five-time increase?
    Mr. Evans. Well, five times increase from where our 
current----
    Mr. Pearce. An increase in the cost.
    Mr. Evans. Well, we probably would, because our 
CO2 cost right now is very, very low. So five times 
our cost, we could still do it.
    I don't think people in the Permian Basin and Rocky 
Mountains probably could accept that kind of increase.
    Mr. Pearce. Your project is based on Mr. Kunkel's building 
of his project, and his project is dependent on legislation. 
The European countries are finding that cap-and-trade is just 
too expensive. I think that might be what caused Mr. Duncan's 
head to hurt about it, that the European countries are backing 
away from it.
    What are you going to do in your project if Mr. Kunkel 
doesn't build his? Are you still going to go ahead with your 
project to put CO2 in the ground?
    Mr. Evans. Well, our primary focus is not power. 
Unfortunately, their costs are very, very high, especially for 
power not generated by gasification.
    Mr. Pearce. That is not my question. My question is, are 
you going to keep on the project if Mr. Kunkel doesn't build 
his project? Are you going to stay on your project?
    Mr. Evans. Well, not if I was only tied to his project.
    Mr. Pearce. But that is my question. You are so tied to it 
that you will not, is that my understanding?
    Mr. Evans. No, sir. Actually, Denbury and Tenaska are not 
tied together at all. In fact, we are not working on that 
project with them.
    If that was a similar project in our area of the country, 
and that was our only choice of CO2, no, that would, 
his price of CO2 would not be economical for us to 
continue.
    Mr. Pearce. All right, Mr. Chairman. I have a lot to think 
about, I think. Thanks. I appreciate it.
    Mr. Costa. Thank you for your good questions, as always. 
Members of the panel, thank you for your patience. I am sorry 
that we had to have a break.
    Mr. Pearce. Wait, I am going to have unanimous consent to--
--
    Mr. Costa. OK. And obviously this is an issue that has a 
great deal of interest, and your testimony is focused on that. 
And we will continue to work with you as we try to chart a 
course that can continue this effort that I think has a lot of 
potential benefit to our country's energy needs.
    Mr. Pearce.
    Mr. Pearce. OK. We have a report from the Department of 
Energy about enhanced oil recovery. I would like unanimous 
consent to submit that.
    Mr. Costa. Without objection.
    Mr. Pearce. And additionally, an editorial from yesterday's 
Investor's Business Daily, American Energy Production. I am 
requesting unanimous consent to submit that for the record.
    Mr. Costa. Without objection.
    [NOTE: The article submitted for the record has been 
retained in the Committee's official files.]
    Mr. Costa. Anyway, once again, I thank the members of the 
Committee. Thanks to the staff. And I apologize for the way the 
hearing got elongated today. But your expertise and your 
information is very valuable, as we look at the policy 
considerations that we have to consider as we pursue hopefully 
that bipartisan energy policy that I think is in the best 
interest for all of America, given the energy crisis we are 
facing.
    This hearing is now adjourned.
    [Whereupon, at 1:04 p.m., the Subcommittee was adjourned.]

    [Additional material submitted for the record follows:]

    [A statement submitted for the record by George Peridas, 
Ph.D., Science Fellow, Climate Center, Natural Resources 
Defense Council, follows:]

          Statement of George Peridas, Ph.D., Science Fellow, 
           Climate Center, Natural Resources Defense Council

    We thank the House Natural Resources Committee, Subcommittee on 
Energy and Mineral Resources for the opportunity to submit written 
testimony for its June 12th, 2008 oversight hearing on ``Spinning Straw 
Into Black Gold: Enhanced Oil Recovery Using Carbon Dioxide''. NRDC is 
a national, nonprofit organization of scientists, lawyers and 
environmental specialists dedicated to protecting public health and the 
environment. Founded in 1970, NRDC has more than 1.2 million members 
and online activists nationwide, served from offices in New York, 
Washington D.C., San Francisco, Los Angeles, Chicago and Beijing.
    The Subcommittee's examination of the topic of Enhanced Oil 
Recovery using Carbon Dioxide (CO2-EOR) is extremely 
topical. The United States are faced with two related challenges that 
demand prompt action: energy independence and climate change.
    First, we must ensure that our nation can meet its energy needs 
securely, affordably and efficiently, without being subject to world 
energy price shocks or relying on unstable regions for its fuel 
supplies.
    Second, as the developed world's largest greenhouse gas emitter--
and until very recently the world's largest emitter 1--we 
must also take prompt action to reduce these emissions substantially in 
order to avoid the worst effects of climate change on this country and 
the rest of the planet, as well as the significant costs associated 
with it, which will be significant for many regions of the country.
---------------------------------------------------------------------------
    \1\ Estimates indicate that China surpassed the U.S. in emissions 
in 2007.
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    CO2-EOR offers an opportunity to take positive action on 
both challenges by making use of an untapped domestic oil resource 
without the worst impacts of other production methods or proposals, 
while permanently sequestering CO2 from anthropogenic 
sources underground. To put the opportunity in perspective, a recently 
updated survey of the CO2-EOR potential in the United States 
prepared for the U.S. Department of Energy estimates that as much as 48 
billion barrels of ``stranded oil'' from existing fields--more than 
double the approximately 22 billion barrels of proven U.S. reserves--
would be economical to produce at recent years' high oil prices. 
2 At $100/barrel, that amounts to $4.8 trillion tied to 
domestic oil reserves that would create a multi-decade market for more 
than 11.5 billion tons of CO2, almost all of which will need 
to come from industrial sources that otherwise would be emitted to the 
atmosphere.
---------------------------------------------------------------------------
    \2\ ``Storing CO2 with Enhanced Oil Recovery'', DOE/
NETL-402/1312/02-07-08, February 2008.
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    In our view, the urgent challenges of our national and global 
dependence on oil and escalating global warming pollution both demand 
rapid investment in efficiency and cleaner sources of energy. NRDC also 
believes that carbon capture and geologic storage from coal-fired power 
plants and other large industrial sources will be necessary to achieve 
the deep emission reductions that will be needed. We believe that 
CO2-EOR, implemented with the appropriate measures to ensure 
long-term geologic sequestration, provides a very significant 
opportunity to advance carbon capture and storage, reduce industrial 
emissions and to sustain domestic oil projection without drilling in 
environmentally sensitive areas.
Our oil addiction
    In his 2006 State of the Union address, President Bush famously 
admitted that America is addicted to oil. Indeed, the U.S. consumes oil 
at an astonishing rate of roughly 21 million barrels/day or a quarter 
of the oil produced globally, 70% of which is used in the 
transportation sector. According to the DOE-EIA Annual Energy Outlook, 
we import twice as much oil as we produce domestically, meaning that a 
staggering two-thirds of our oil is imported. Domestic oil production 
has been dropping steadily since the 1970s as the figure below shows, 
and the nation's dependence on imported oil is project to increase 
steadily according to the EIA. Depending so heavily on an imported 
resource so crucial to the economy is without question unwise--and the 
policy decisions that will affect whether this will be the case are 
being made today.

    [GRAPHIC NOT AVAILABLE IN TIFF FORMAT]


    Until recently, the nation had grown complacent about oil use. 
The price of oil remained under $20/barrel in nominal terms for much of 
the 1990s, creating an illusion of an inexpensive commodity. Since 2002 
however, oil prices have been climbing ever upwards, surging to almost 
$140/barrel in June 2008. It is clear that the era of cheap oil--and 
cheap fossil fuels more generally for that matter--is over in all 
likelihood. With strong demand in the developed world and an ever-
increasing pressure coming from the developing countries, a world of 
high or rising oil prices is a distinct possibility and one predicted 
by several analysts.
    The economic impacts of the recent surges are being felt worst of 
all by the poorest families and communities. Yet high prices have not 
slowed us down. Even in the context of sustained high oil prices in the 
last five years, fuel use trends remain largely unchanged, and our 
transportation fuel demand continues to rise relentlessly. Only now is 
evidence emerging that consumers are turning to more fuel-efficient 
vehicles and away from ``gas-guzzlers'', an effect that is making 
automakers resort to plant closures and shift their fleet to the kind 
of vehicle that ought to have been the obvious choice and the correct 
business decision long ago.
    It does not take an expert to work out that our current path is 
unwise from an economic point of view, from a national security point 
of view, or from an environmental point of view.
A changing climate
    Alongside surging oil prices and demand, the planet's climate is 
changing fast. Greenhouse gas emissions from the use of fossil fuels, 
mainly CO2, are having a profound effect on our planet, 
presenting us with one of the most significant environmental and social 
challenges of the century.
    In its most recent Assessment Report last year, the 
Intergovernmental Panel on Climate Change, an independent scientific 
body, issued the loudest warning to date, calling the warming in the 
climate system ``unequivocal'' and calling for serious emission 
reductions if we are to avoid truly dangerous greenhouse gas 
concentrations. Failure to pursue significant reductions in greenhouse 
gas emissions very soon will make the job much harder in the future--
both the job of stabilizing atmospheric pollution concentrations and 
the job of avoiding the worst impacts of climate chaos.
    A growing body of scientific research indicates that we face 
extreme dangers to human health, economic well-being, and the 
ecosystems on which we depend if global average temperatures are 
allowed to increase by more than 2 degrees Fahrenheit from today's 
levels. We have good prospects of staying below this temperature 
increase if atmospheric concentrations of CO2 and other 
global warming gases are kept from exceeding 450 ppm (parts per 
million) CO2-equivalent and then rapidly reduced. To make 
this possible requires immediate steps to reduce global emissions over 
the next several decades, including action to halt U.S. emissions 
growth within the next few years and then cut emissions by 
approximately 80% by mid-century. This goal is ambitious, but 
achievable. It can be done through an annual rate of emissions 
reductions that ramps up to about a 4% reduction per year. Fortunately, 
a wide variety of tools is available today to achieve those 
reductions--but we will need all the tools at our disposal. One such 
tool is Carbon Capture & Sequestration (CCS).
Carbon capture & sequestration (CCS)
    Given the world's and the nation's dependence on fossil fuels, it 
is essential to have in place a technology and a strategy to reduce 
greenhouse gas emissions from large industrial facilities that burn 
these fuels, even though their complete phase-out through energy 
efficiency improvements and a transition to renewable fuel sources 
might be technically and theoretically possible. Using all available 
tools is a wise and necessary hedging strategy in the face of the steep 
emission cuts that are needed. Projections differ as to the exact 
portion of reductions that will be delivered by different technologies, 
but from a strategic point of view, CCS provides a much needed answer 
for fossil fuel use--which is inevitable.
    Coal by itself, the most carbon-intensive of fossil fuels presents 
the biggest climate challenge. Since the dawn of the industrial age, 
human use of coal has released about 150 billion metric tons of carbon 
into the atmosphere--about half the total carbon emissions due to 
fossil fuel use in human history. Another 4 trillion metric tons of 
carbon are contained in the remaining global coal resources. That is a 
carbon pool nearly seven times greater than the amount in our pre-
industrial atmosphere. Using that coal without capturing and disposing 
of its carbon means a climate catastrophe. And the die is being cast 
for that catastrophe today, not decades from now. According to the 
International Energy Agency, over 1800 GW of new coal plants will be 
built between now and 2030, a capacity equivalent to 3000 large coal 
plants, or an average of ten new coal plants every month for the next 
quarter century. This new capacity amounts to 1.5 times the total of 
all the coal plants operating in the world today.
    Continuing with the use of coal without capturing and sequestering 
is fundamentally incompatible with climate stabilization. NRDC believes 
that CCS technology is available to us today to begin deployment.
    Research on CCS has been ongoing for many years now, with major 
international conferences taking place since the early 1990s. Since 
then, knowledge on the subject has greatly expanded, to the extent that 
the Intergovernmental Panel on Climate Change (``IPCC'') issued a 
special report on CCS in 2005. An extensive Massachusetts Institute of 
Technology (``MIT'') study on the Future of Coal in 2007 also examined 
CCS in depth. There is a substantial body of evidence, knowledge, and 
peer-reviewed literature on CCS.
    In many ways, CCS is not new. There are three elements to 
successful geologic sequestration of carbon dioxide: capture, 
transportation, and sequestration. All three of these elements have 
been demonstrated and operated in commercial, large scale 
installations.
    The first element of CCS is the initial capture of the carbon 
dioxide emissions. ``Pre-combustion capture'' is applied to conversion 
processes that gasify coal, petroleum coke, or other feedstocks (such 
as biomass) rather than combusting them in air. In the oxygen-blown 
gasification process, the feedstock is heated under pressure with a 
mixture of pure oxygen, producing an energy-rich gas stream consisting 
mostly of hydrogen and carbon monoxide. Coal gasification is widely 
used in industrial processes around the world, such as in ammonia and 
fertilizer production. Hundreds of such industrial gasifiers are in 
operation today. In power generation applications as practiced today 
this ``syngas'' stream is cleaned of some impurities and then burned in 
a combustion turbine to make electricity in a process known as 
Integrated Gasification Combined Cycle (``IGCC''). Commercially 
demonstrated systems for pre-combustion capture from the coal 
gasification process involve treating the syngas to form a mixture of 
hydrogen and CO2, and then separating the CO2 
primarily through the use of solvents. These same techniques are used 
in industrial plants to separate CO2 from natural gas and to 
make chemicals such as ammonia out of gasified coal. However, because 
CO2 can be released to the air in unlimited amounts under 
today's laws, except in niche applications, even plants that separate 
CO2 do not capture it; rather, they release it to the 
atmosphere. Notable exceptions include the Dakota Gasification Company 
plant in Beulah, North Dakota, which captures and pipelines more than 
one million tons of CO2 per year from its lignite 
gasification plant to an oil field in Saskatchewan (the Weyburn project 
described below), and ExxonMobil's Shute Creek natural gas processing 
plant in Wyoming, which strips CO2 from sour gas and 
pipelines several million tons per year to oil fields in Colorado and 
Wyoming. The principal obstacle for broad application of pre-combustion 
capture to new power plants (and the main reason behind limited 
deployment of IGCC with carbon capture) is not technical, it is 
economic: under today's laws it is cheaper to release CO2 to 
the air than capture it. Other capture technologies, including post-
combustion and oxyfuel combustion are currently at the bench and/or 
pilot demonstration stage. The cost of CO2 capture is by far 
the most expensive element in the CCS chain of operations, estimated to 
be in the region of 75% of total costs, depending on the geological 
setting and the distance of transport.
    The second element of CCS is the transportation of captured carbon 
dioxide to the injection site, if needed. As we describe further below, 
CO2 pipelines today operate as a mature market technology.
    The third element of CCS is the sequestration of the carbon dioxide 
in geological formations. Injection of carbon dioxide has been 
successfully demonstrated on a large scale, not least in the context of 
CO2-EOR projects, some of which like Seminole, SACROC and 
Wasson are injecting annual amounts of CO2 well above the 
quantity that a 500MW coal plant would produce. There is also 
considerable scientific knowledge regarding the mechanisms for trapping 
carbon dioxide in sedimentary geological formations. For example, 
residual trapping limits carbon dioxide mobility through capillary 
forces. Solubility trapping occurs when injected carbon dioxide 
dissolves in fluids within the geological formation. Stratigraphic 
trapping occurs when overlying impermeable rock formations prevent 
upward movement of carbon dioxide from underlying reservoirs. 
Mineralization trapping occurs when injected carbon dioxide forms 
carbonate minerals and essential becomes part of the solid rock into 
which it was injected. Both the Intergovernmental Panel on Climate 
Change (``IPCC'') and the interdisciplinary team from the Massachusetts 
Institute of Technology (``MIT'') concluded that such sequestration 
methods in appropriately selected and operated geologic reservoirs are 
likely to trap over 99% of injected carbon dioxide over 1,000 years. 
This conclusion is based on existing project performance and a number 
of natural and industrial analogs. Nature itself has stored 
hydrocarbons and CO2 for millions to hundreds of millions of 
years, and humans have successfully stored natural gas and other fluids 
underground.
    There are several commercial and research projects that inject 
carbon dioxide in sedimentary geological formations for permanent 
sequestration. For example, the Sleipner project in Norway has been 
operating since 1996 and injects about 1 million tons of CO2 
annually into a deep saline formation in the North Sea. BP's In Salah 
project, operating in Algeria since 2004, injects a similar amount of 
CO2 stripped from natural gas back into the water leg of the 
natural gas field. The Weyburn project receives CO2 captured 
and transported from North Dakota to Saskatchewan and has been 
operating since 2000 and injects 1-2 million tons of CO2 
annually. All three of these projects include monitoring programs. The 
results of that monitoring indicate that the CO2 is 
remaining sequestered in the formations and that there is no reason to 
expect any CO2 leakage from these projects. These projects 
just mentioned give me a great deal of confidence that CO2 
can remain permanently sequestered in geological reservoirs.
    All components of CCS therefore--capture, transportation and 
injection--have been demonstrated at commercial scale in a number of 
industrial applications. We believe that the barriers to CCS are not 
technological, but rather economic and regulatory. We are joined by 
leaders of major industrial corporations such as NRG Energy and BP, who 
have stated their case as follows:
        ``We're Carboholics. Make Us Stop. We are not running out of 
        time; we have run out of time. We need to move as quickly as 
        possible toward implementing the low-emissions ways of 
        combusting coal that are under development or, in the case of 
        ``coal gasification'' technology, are ready for commercial 
        deployment.''
[David Crane, CEO of NRG Energy; Washington Post, October 14, 2007]
        ``CCS cannot succeed as a commercially successful emission 
        abatement technology without the policy or regulatory 
        frameworks that would allow commercial entities to invest in 
        it. New technology cannot be `pushed' into industrial-scale 
        deployment, a market is necessary to `pull' it. Deploying CCS 
        at scale is not as much a question of technology availability 
        but of economic viability. CCS is available today to play a 
        significant role in reducing greenhouse gas emissions and 
        addressing climate change''.
[Robert Malone, Chairman and President, BP America; Written Testimony 
Submitted to the Select Committee on Energy Independence and Global 
Warming U.S. House of Representatives, September 21, 2007]
    The reason that no large integrated power sector CCS project exists 
today is purely economic: it is simply cheaper to vent the 
CO2 under today's laws instead capturing it, compressing it, 
transporting it to a suitable reservoir and sequestering it. However, 
this is not an indication of the state of readiness of the technology. 
The USDOE is also leading a national research program on CCS. Although 
we applaud the efforts of the dedicated and talented individuals 
involved in this program, the resources and funding available are not 
in line with the deployment timescale needed for CCS to reduce 
emissions meaningfully. Without an economy-wide cap-and-trade scheme 
that prices carbon emissions, and without targeted and reliably funded 
(such as auction revenues, as opposed to the notoriously unreliable 
appropriations) incentives to bring down the costs of CCS in the 
initial years when the carbon price is too low and volatile to spur 
investment, CCS is destined to linger in the background as it has done 
until now. We are convinced, however that, under such a policy 
framework, hundreds of MWs of power sector CCS would be deployed in the 
early years. The DOE's targets and timelines should not be seen as 
representative of the technology, or its program as the gateway to CCS.
Addressing energy independence and climate change
    Weaning ourselves off foreign oil, while at the same time 
addressing climate change, is achievable if we make the right choices. 
In a world of climbing prices, increased dependence on imports, 
geopolitical instability and rising emissions, the obvious focus should 
be the more efficient use of energy and oil, and its replacement to the 
extent possible with cleaner, sustainable alternatives.
    Solutions abound: more efficient vehicles, expanded use of public 
transport, smart city planning, low carbon fuels such as sustainably 
grown biofuels, plug-in-hybrid vehicles powered by low carbon 
electricity are all options that are available to us today. Our first 
priority should be to substitute oil by improving end-use efficiency, 
and by sustainable, low-carbon alternatives as fast as possible. These 
resources are cleaner, and the diversity that they will provide is our 
most powerful weapon against oil profiteers domestically and abroad. On 
the topic of domestic production, we should fully exploit the fields we 
have already explored and developed. America's existing oil fields hold 
billions of barrels of oil that we know are there and can be produced 
at reliable costs with no added environmental damage. CO2-
EOR is key to tapping this resource.
    In order for these solutions to deliver on their potential, 
concerted policy efforts will be needed--and this will take decisive 
action, political vision and leadership. Now is the time to make the 
right choices on how to fuel our future growth, and to move in an 
efficient, low-carbon direction.
The false promises of drilling and unconventional fuels
    In the face of high oil prices and energy security concerns, a 
number of proposals have been put on the table that would allegedly 
come to the rescue. These include drilling in environmentally sensitive 
or protected areas such as the Arctic National Wildlife Refuge (ANWR) 
or on the Outer Continental Shelf (OCS), or resorting to unconventional 
oil sources such as tar sands and oil shale.
    Drilling in ANWR and on the OCS has been restricted in order to 
protect a few of the remaining special places in America from the 
industrialization that accompanies energy exploitation, and because an 
expansion of drilling in these areas will do precious little to benefit 
Americans--the U.S. can meet its energy needs without opening these 
areas to drilling and accompanying industrial activities. Both of these 
premises remain true today, even though unrelated forces have resulted 
in an increase in prices at the gas pump. It remains true that complete 
exploitation of these areas would not reduce America's transportation 
fuel bill. Efforts to expand drilling in those areas amount to nothing 
more than attempts by special interests to stockpile and secure market 
share. However, there are a combination of actions that can provide 
real and long-lasting relief while protecting these special places as 
part of the bargain.
    The Arctic National Wildlife Refuge, a pristine area located in 
northeast Alaska, is the nation's second largest national wildlife 
refuge, comprising 19 million acres. It is home to nearly 200 wildlife 
species. Because of its abundant and diverse wildlife, the refuge is 
often likened to Africa's Serengeti. Scientists consider the coastal 
plain, which has been proposed for drilling, to be the biological heart 
of the entire refuge, containing caribou, polar bears, grizzly bears, 
wolves, and various migratory birds, several of which are protected by 
international treaties or agreements. The refuge was created in 1960 by 
Congress to specifically protect the region's wildlife.
    In addition to the wilderness value of the refuge, drilling there 
will do nothing to relieve prices at the pump for a number of reasons, 
which are aptly summarized in a recent report by Majority staff of this 
Committee 3, drawing on official departmental statistics and 
reports:
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    \3\ ``The Truth About America's Energy: Big Oil Stockpiles Supplies 
and Pockets Profits''; A Special Report by the House Committee on 
Natural Resources Majority Staff, June 2008.
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      It is not clear exactly how much oil could be extracted. 
It may be possible that up to 11 billion barrels of crude oil is in 
place. However, the amount of this oil that can actually be recovered 
due to technological and economic reasons is significantly less. In a 
recent study, the DOE's Energy Information Administration estimated 
that the cumulative additional oil production from ANWR could be as low 
as 1.9 billion barrels, with an upper estimate of 4.3 billion barrels. 
4
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    \4\ ``Analysis of Crude Oil Production in the Arctic National 
Wildlife Refuge''. Energy Information Administration Office of 
Integrated Analysis and Forecasting U.S. Department of Energy; May 2008
---------------------------------------------------------------------------
      A vast acreage is open and available for leasing in 
Alaska outside ANWR. However, companies have leased only a fraction of 
this land and produced very little or no oil. 5
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    \5\ Approximately 91 million acres are currently open to leasing in 
the Arctic region of Alaska onshore and offshore. Oil and gas companies 
have leased only 11.8 million of these. Within the National Petroleum 
Reserve in Alaska, around 3 million acres out of 22.6 have been leased. 
No oil has been produced those lands and industry has drilled only 25 
exploratory wells there since 2000.
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      It will take a decade before oil can be produced from 
ANWR, and another decade before oil production reaches its peak.
      The total production from ANWR would pale in comparison 
with total U.S. demand, and also in comparison to the production 
potential from CO2-EOR from depleted fields.
    Pretty much the same realities apply to drilling on the OCS. 
Drilling in these areas poses unacceptable environmental risks of oil 
spills, air and water pollution, seismic impacts on marine mammals and 
onshore damage. Drilling is not necessary, given that estimates by the 
Minerals Management Service (MMS) show that 60% of the untapped 
economically recoverable oil and 80% of the untapped economically 
recoverable oil and/or natural gas on the OCS are located in areas that 
are currently open for leasing to industry.
    Perhaps most importantly, feeding our addiction does nothing to 
decrease our dependence on oil. Moreover, oil prices are set by global 
markets. There is absolutely no evidence to show that increased 
domestic production will result in more than a few cents worth of lower 
prices at the pump--in fact although between 1999 and 2007, the number 
of drilling permits issued for development of public lands has more 
than tripled, oil and gasoline prices have risen to today's levels 
regardless. We also cannot hide the fact that the local and cumulative 
impacts from the expansion in leases and permits has also been 
significant. Many leases are located in areas where the carrying 
capacity for development has been, or is very close to being exceeded, 
and in most areas development is taking place without an overall 
development plan or in a phased manner. Nor is the characterization of 
no-go areas accurate. In some regions such as California, despite the 
absence of ``new'' drilling for some years now, there a substantial 
ongoing legacy program. All in all, recent years have been 
characterized by a fury of domestic drilling under permissive federal 
regulators, with plenty of unused leases still available in reserve. 
Despite this activity, prices have soared and the share of imports has 
risen.
    The only sound and possible way to decrease prices and ensure a 
secure energy supply for the nation is to move away from the paradigm 
of meeting uncontrolled demand growth, use oil more efficiently and to 
replace it with other, low-carbon fuels. We just cannot drill our way 
out of our oil dependence. Attempts to mislead the public into 
believing that the protection of sensitive areas from drilling is 
responsible for today's ills are irresponsible and not in the interest 
of the American people, who will ultimately be the judges of the 
policies that come out of Congress. Increasing fuel efficiency 
standards for new vehicles to 40 miles per gallon would save more than 
ten times the likely yield of oil from ANWR. It is short-sighted and 
unwise to think of degrading an irreplaceable refuge to get a few cents 
of relief from higher gas prices, rather than encouraging Detroit to 
make more efficient cars and employing Americans in clean energy jobs. 
Fortunately we moved a step closer to the right path this past year 
when Congress required automakers to build cars and light trucks that 
average at least 35 mpg by 2020. By raising the fuel-efficiency bar 
even higher, we will be well on our way to beating the addiction. The 
public has realized that, and automakers are feeling the impacts: only 
recently General Motors announced that it is closing four plants that 
produce sport utility vehicles and pickup trucks in North America, 
prompted by soaring gas prices and slumping sales in the area. At the 
same time, GM plans a new emphasis on compact cars and is reviewing the 
future of the giant ``Hummer''.
    Unconventional fuels are no exception. In the name of energy 
independence and lowering gas prices, proponents would have us believe 
that producing transportation fuels from tar sands, oil shale and coal 
are a sensible solution. These resources can be accessed domestically 
in the U.S. or in friendly Canada just across the border. The 
technologies to convert these unconventional resources into fuels had 
seen very limited application for years due to their high cost and 
market risk, but current high oil prices are spurring a flurry of 
development. Tempting though these resources might seem, they carry a 
host of economic and environmental problems, and unsurprisingly are not 
the answer to our oil addiction either.
    Whether it is scouring the earth for the tar-like substance mixed 
with sands excavated from under the Boreal forests of Alberta, Canada, 
mining shale under the U.S. Rockies, or stripping coal from the 
mountains of the American West and Appalachia to manufacture synthetic 
liquid fuel, these unconventional sources constitute a heavy 
environmental burden to communities and ecosystems--both local and 
global.
    Fuel production from these sources is extremely energy intensive, 
and the production process emits a far higher amount of greenhouse gas 
emissions than conventional oil production--often whole multiples of 
that amount. In a carbon-constrained world, these fuels will have to 
shoulder the additional cost of their high carbon content, and will not 
fare well either under cap-and-trade regimes or low carbon fuel 
standards that are now being legislated in a number of states and 
Canadian provinces and will likely be Federal policy in the U.S. soon. 
Producing fuel from tar sands, oil shale, and liquid coal is not only 
environmentally risky, but also a risky business proposition. In the 
near future, the United States is likely to join Europe and Japan in 
adopting mandatory limits on global warming pollution. Businesses 
developing these highly polluting fuels will likely find they are poor 
investments in a global market that increasingly values clean, low-
carbon energy technologies. Moreover, taxpayers are being asked to 
share the bill for these risky deals through government subsidies and 
entitlements. Taxpayers and investors alike should be wary of putting 
their dollars into risky ventures involving carbon-intensive fuels. 
Extraction of all three resources also comes at enormous cost to our 
water, air, forests, wetlands, and wildlife and places serious burdens 
on community infrastructure and public health.
    Destroying wildlife habitat to extract those costly resources at a 
significant expense to the climate is also not the way to wean 
ourselves off oil. Some have characterized tapping into these resources 
as ``scraping the bottom of the barrel'', which aptly describes how 
little those resources would do to reduce oil consumption domestically, 
or affect the price we pay for oil. Supply concerns are unlikely to be 
eased by the growing clout of the world's oil cartel, the Organization 
of Petroleum Exporting Countries (OPEC). OPEC countries hold over 75% 
of the world's oil reserves according to current estimates. EIA 
estimates that members of OPEC earned $673 billion in net oil export 
revenues in 2007, a 10% increase from 2006, with Saudi Arabia earning 
the largest share of these earnings at $194 billion or 29% of total 
revenues. This immense market power enables the organization to control 
world oil prices effectively, leaving limited or no scope for the U.S., 
which holds a meager 3% of global oil supply, to ease price pressures 
through additional production.
    Could CO2-EOR offer a better alternative to uncontrolled 
drilling in wild places and dirty fuels, alongside conservation 
policies and clean, sustainable fuels?
Enhanced oil recovery as an untapped domestic fuel source and 
        CO2 sink
    Stranded oil is oil that is left in the reservoir after primary and 
secondary recovery techniques. Enhanced oil recovery through 
CO2 flooding can reduce the amount of stranded oil 
significantly. Of the original oil in place (OOIP), 5-40% is usually 
recovered in the primary production phase. An additional 10-20% of oil 
in place is produced by secondary recovery that uses water flooding. 
Various miscible agents, among them CO2, have been used for 
enhanced, or tertiary, oil recovery with an incremental recovery of 7-
23% (averaging around 13.2%) of the original oil in place. The exact 
number is highly reservoir specific.
    The use of CO2 for EOR began in the U.S. in the early 
1960s. Inexpensive industrial CO2 sources, such as natural 
gas processing plants, were initially used, although to sustain the 
expansion this was quickly supplemented and eventually overshadowed by 
naturally occurring CO2 discovered in Colorado, New Mexico 
and Mississippi. Today, there are around one hundred registered 
CO2 floods worldwide, almost 90% of which are in the U.S. 
and Canada. Some 35 million tons of CO2 annually are 
injected in mature oil reservoirs. These floods are primarily in the 
Permian Basin of Texas and New Mexico, but also in the Bighorn Basin of 
Wyoming, the Rangeley Field of Colorado and the Mississippi Salt Basin. 
In North Dakota CO2 from the Great Plains Synfuels project 
is captured and transported across the border to Canada, and injected 
into the Weyburn and Midale fields in Saskatchewan. CO2 
pipelines today operate as a mature market technology and are the most 
common method for transporting CO2. The first long-distance 
CO2 pipeline came into operation in the early 1970s. In the 
United States, over 3,000 miles of pipeline transports more than 40 
million tons CO2 per year for use in CO2-EOR.
    The growth of CO2-EOR as a technique has been contained 
for a number of reasons. The primary reason is the relative scarcity of 
high-volume sources of pure CO2 that is needed for EOR 
operations. This in turn has put a premium on the cost of 
CO2 to operate the floods, which can add up to half the 
total costs of a CO2-EOR project. The cost of capturing 
anthropogenic CO2 and using finite supplies of 
CO2 that is being produced from natural domes (in much the 
same way as oil and gas) has thus kept projects in check. Another 
reason relates to lead times: it can take two years or more for the 
production to respond to the CO2 being injected, delaying 
revenues, increasing risks and making financing less favorable. 
Moreover, different fields' response to CO2 flooding can be 
highly variable, making successful operation a site-specific affair. 
Rising oil prices however, have now made CO2-EOR economics 
look far more attractive. CO2 supply for EOR is more choked 
than ever, and companies are pursuing aggressive business models to 
expand their operations using anthropogenic CO2.
    The Department of Energy (DOE) has collaborated with Advanced 
Resources International (ARI) to produce estimates of the volumes of 
oil that could be produced and the CO2 that can be stored 
through CO2-EOR in the U.S. The latest iteration of the 
study 6, issued in February 2008, builds on the previously 
issued ``Basin Studies'' and makes the case for a very significant 
domestic CO2-EOR potential. Specifically, it evaluates the 
total stranded oil at roughly 400 billion barrels, 85 billion of which 
is ``technically recoverable'' using state-of-the-art CO2-
EOR techniques, with 45 billion being ``economically recoverable'' at 
an oil price of $70. At current levels, the economically and 
technically recoverable estimates represent approximately 5-10 full 
years worth of our oil consumption. The base case for the economically 
feasible market demand for CO2 estimates are approximately 
7.5 billion tons of CO2 in the lower 48 states, and 9.3 
billion tons of CO2 in the whole of the U.S.--this is well 
in excess of the nation's annual CO2 emissions of 
approximately 6 billion tons of CO2. This is a significant 
sequestration potential. Even today's injection levels of approximately 
35 million tons per year amount to the emission from five large coal 
power plants which, although would not solve our CO2 problem 
still represents a significant quantity.
---------------------------------------------------------------------------
    \6\ ``Storing CO2 with Enhanced Oil Recovery'', DOE/
NETL-402/1312/02-07-08, February 2008.
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    Easing the CO2 supply and cost constraints would enable 
the much larger cited potential to be tapped. The International 
Resources Group recently conducted an analysis of the proposed 
Lieberman-Warner conducted for NRDC, using an improved and extended 
version of the U.S. national MARKAL model (US-NM50) originally 
developed by the Environmental Protection Agency's Office of Research 
and Development. The reference point for the analysis is a business-as-
usual (BAU) scenario calibrated to the Department of Energy's 2008 
Annual Energy Outlook. The results demonstrate the power of 
CO2-EOR combined with efficiency: oil imports drop to 35% of 
total oil supply in the middle years of the period under study due to 
both lower demand and through CCS using CO2-EOR that greatly 
expands domestic production from existing fields. Oil imports rise 
again between 2035 and 2050 as the EOR resource begins to deplete, 
although they remain under 60% of total oil supply, as compared to more 
than 80% by 2050 in the BAU case. The figure below illustrates the 
analysis results--the two scenarios correspond to different mixes of 
renewable and CCS power generation:

    [GRAPHIC NOT AVAILABLE IN TIFF FORMAT]



    CO2-EOR in our view therefore has a substantial 
immediate- to long-term role to play in both increasing domestic oil 
production in a responsible way, and in sequestering CO2. 
Although global and national CO2 storage capacity estimates 
in deep saline formations dwarf those in depleted oil and gas fields, 
it will be several years before EOR capacity is depleted in the U.S. In 
this interim period, the added revenues from oil production can help 
offset the costs of capturing CO2 from industrial sources 
and the costs of expanding the pipeline network for CO2.
Key questions and recommendations
    We conclude by answering some of the key questions around 
CO2-EOR as a domestic source of oil and a CO2 
abatement technology.
Why pursue further drilling when we should be breaking our dependence 
        on oil?
    Breaking the dependence on foreign oil--and oil in general--should 
be the first priority as this testimony has argued. However, America 
will continue to depend to some extent on oil for some years to come. 
Sourcing this oil domestically is advantageous over importing it. Oil 
produced from CO2-EOR in already drilled, mature fields is 
far preferable to oil that would be produced from ecologically 
sensitive areas of the country. Existing wells and pads can be used, 
reducing the need for further disruptions. The CO2 pipeline 
network for EOR can provide the backbone for a national sequestration 
pipeline network. Moreover, an expansion in the CO2-EOR 
business can have more direct beneficial effects to local and state 
economies and workforces, as operators are almost entirely small- to 
medium-size independent producers as opposed to the majors.
What about the CO2 emissions from the produced oil?
    The oil produced from CO2-EOR will emit CO2 
when refined and combusted. The key factor in determining whether these 
emissions are additional, however, is to look at overall oil demand. If 
the quantity of oil produced through CO2-EOR is substantial 
enough to reduce prices and induce an increase in national consumption, 
then the emissions are additional. In practice, however, 
CO2-EOR oil would be limited in quantity would simply be 
displacing imported oil without resulting in additional emissions.
    Regarding the suggested notion of ``green oil'', which has been 
suggested to capture the fact that oil from CO2-EOR might 
have resulted in the sequestration of anthropogenic CO2, we 
feel that it is simpler and more appropriate to account for the reduced 
emissions at the source of the CO2, whether this is a power 
plant, refinery, ethanol plant or other facility that would be 
regulated under climate legislation.
How is business-as-usual CO2-EOR different to CCS?
    CO2-EOR is not tantamount to CCS. In the former, the 
objective of the process is to maximize oil yields using the least 
amount of CO2, which has to be bought in as a resource, 
often at some expense. The objective of sequestration on the other hand 
is to maximize the amount of CO2 stored in the geological 
formation, and to ensure permanence of storage. However, the extensive 
body of technical expertise gained from CO2-EOR practices is 
directly related to CCS. Conventional injection techniques used in EOR 
in combination with a few simple additions can ensure permanent storage 
and provide the assurances needed for a CO2-EOR project to 
qualify as sequestration.
    Specifically, these steps would be:
      A more extensive geological site characterization that 
establishes the containment characteristics and mechanisms present in 
potential reservoirs.
      Proven monitoring and verification systems capable of 
tracking the evolution of CO2 in the subsurface and either 
verify containment or provide triggers for remedial action.
      Mitigation or remediation actions to ensure that 
CO2 remains contained underground without endangering 
underground sources of drinking water or being released to the 
atmosphere.
      Appropriate accounting provisions.
    All of these steps and techniques can be performed today by 
research and commercial entities alike at a small fraction of the cost 
of capturing the CO2.
    A geological site characterization assesses the ability of a 
reservoir to retain CO2 for long periods of time, or 
indefinitely for all intents and purposes. It assesses the capacity and 
injectivity of the reservoir, the effectiveness of the trapping 
mechanisms, the integrity of the caprock, as well as other risk 
factors. The presence of oil in reservoirs is itself evidence that they 
have the ability to trap fluids over long periods. However, a more 
careful study of the specific reservoir characteristics is needed to 
pick secure, non-leaky reservoirs with the desirable injection and 
retaining characteristics. Geologists and the oil industry have the 
necessary tools at the disposal to perform this evaluation at a modest 
cost, especially in fields that have been drilled and operated for 
years. The impact of existing wells at the proposed site, as well as 
their construction standards, should be evaluated as an integral part 
of the site characterization.
    A robust program for monitoring CO2 in the subsurface is 
an integral component of sequestration. Such a program, typically 
referred to as Monitoring, Measuring, and Valuation (``MMV''), has the 
role of tracking the evolution of CO2 in the subsurface and 
either verifying containment or providing triggers for remedial action, 
while serving as a continuous source of data feedback for the reservoir 
models that should be used to predict CO2 behavior. A number 
of monitoring techniques and tools are readily available. Selection of 
the appropriate ones and specifics of their use is very site- and 
medium-specific, and should follow directly from the information that 
the site characterization study would reveal. The monitoring regime 
should also include methods to detect potential leakage from wells, 
which are the more likely conduits for migration as opposed to 
geological pathways in well-selected reservoirs. This is particularly 
important in areas of high drilling and well density.
    In addition to monitoring, mitigation and remediation procedures 
need to be studied and specified prior to injection to ensure that 
CO2 will remain contained underground without endangering 
underground sources of drinking water or being released to the 
atmosphere. That said, experience and research indicate that the risk 
of such leaks are minimal in properly selected and operated reservoirs. 
We are not aware of any cases or studies in the history of 
CO2-EOR that point towards groundwater contamination or 
other adverse impacts.
Should the use of naturally sourced CO2 in EOR be 
        discontinued or CO2-EOR regulated differently?
    It is somewhat paradoxical that in a world that desperately needs 
to reduce its CO2 emissions, we are producing CO2 
from geological formations in order to re-inject it. The reasons, or 
course, are economic. We do not believe that the use of naturally 
sourced CO2 should be discontinued. With the right 
incentives for capturing anthropogenic CO2 in place, we 
believe that future growth in CO2-EOR will be done primarily 
on the back of anthropogenic CO2. As this becomes widely 
available and economical, the use of naturally sourced CO2 
can and should be phased out.
    We also do not believe that it is necessary to alter the EPA's or 
the states' Class II Underground Injection Control (UIC) requirements 
for the purposes of business-as-usual EOR. If CO2-EOR is to 
qualify as sequestration, however, we do believe that additional 
provisions are required--as we outline below.
Recommendations
    Cap-and-trade: the most far-reaching measure that will not only 
reduce our greenhouse gas emissions but also reduce our dependence on 
foreign oil, is an economy-wide cap-and-trade scheme, such as that 
proposed by the Lieberman-Warner legislative proposal that was recently 
debated in the Senate. Recognizing that the initial price of 
CO2 is likely to be too low and/or too unstable to stimulate 
sufficient investment in CCS, the bill included a set of targeted 
incentives for carbon sequestration. As the MARKAL analysis described 
earlier in this testimony shows, the bill would provide a significant 
boost to CO2-EOR by making significant supplies of 
CO2 available at affordable prices, greatly reducing oil 
imports.
    Tax treatment for anthropogenic CO2 pipelines: pipelines 
that carry natural CO2 currently qualify for favorable tax 
treatment as master limited partnerships. It is not yet clear whether 
pipelines carrying anthropogenic CO2 would qualify. The tax 
code should be modified explicitly to extend at least as favorable a 
treatment, and preferably favorable, to the pipelines carrying 
anthropogenic CO2.
    Requirements for conversion of EOR to CCS: we believe that 
appropriately modified CO2-EOR projects should be allowed to 
earn carbon allowances under a cap-and-trade scheme. EPA should be 
required to write the relevant accounting protocols for sequestration 
facilities. In addition, we propose the inclusion of conversion 
provisions or a new injection class under the EPA's UIC program that 
will clearly outline how a CO2-EOR project can be converted 
to and classified as a CCS project. The characterization, monitoring 
and remediation/mitigation considerations discussed above, together 
with the accounting protocol, provide a basis for the conversion.
    Subsurface property rights: states have different laws for mineral 
and pore-space rights (which usually belong to the surface owner). With 
very few exceptions, such as Wyoming that recently passed a clarifying 
law, conflicts are resolved through case law, with the mineral estate 
usually being dominant over the surface estate. Sequestration could 
results in conflicts between occupying the pore space with 
CO2 and minerals that might be present in the same 
reservoirs, all between many different owners. We urge that states 
clarify these properly issues, and that the relevant Federal agencies 
clarify provisions for lands under their jurisdiction.
    We would like to thank the Subcommittee again for the opportunity 
to submit written testimony, and stand ready to assist in any way 
possible.

                                 
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