[Congressional Record (Bound Edition), Volume 151 (2005), Part 19]
[House]
[Pages 26516-26537]
[From the U.S. Government Publishing Office, www.gpo.gov]




                                PEAK OIL

  The SPEAKER pro tempore (Mr. Jindal). Under the Speaker's announced 
policy of January 4, 2005, the gentleman from Maryland (Mr. Bartlett) 
is recognized for 60 minutes.
  Mr. BARTLETT of Maryland. Mr. Speaker, I have in front of me a 
document called Peaking of World Oil Production, Impacts, Mitigation 
and Risk Management. As I look at the second page, it says this report 
was prepared as an account of work sponsored by an agency of the United 
States Government. That agency was the Department of Energy, and the 
organization that was funded to do this work was SAIC, a very 
prestigious, scientific organization.
  Dr. Robert Hirsch was a project leader. He was supported by Roger 
Bezdek and Robert Wendling in this very important work. It was 
submitted in February of 2005.
  What I would like to do this evening is to go through the salient 
points of this so-called Hirsch Report. Remember, it was funded by the 
Department of Energy, and it was performed by a very prestigious 
scientific organization, SAIC.
  I have here a quote from page four of this report. This is so 
important, I have highlighted a couple of phrases, but I would like to 
read these couple of statements here, because they are so important. 
The peaking of world oil production presents the United States and the 
world with an unprecedented risk management problem. What that means is 
that never in history has there been a risk management problem like 
this. It is unprecedented, they say.
  As peaking is approached, liquid fuel prices and price volatility 
will increase dramatically and without timely mitigation. The economic, 
social and political costs will be unprecedented.
  Mr. Speaker, what that means is that never in history has there been 
an occasion when economic, social and political costs will be this big. 
Viable, mitigation options exist on both the supply and demand sides, 
but to have substantial impact, they must be initiated more than a 
decade in advance of peaking.
  Dealing with world oil production, peaking will be extremely complex, 
involve literally trillions of dollars. Now, around here, we talk a lot 
about billions of dollars, but seldom about trillions of dollars. This 
will cost trillions of dollars and require many years of intense 
effort.
  Mr. Speaker, what are they talking about? What is this oil peaking 
that they are talking about that is going to present unprecedented 
risk-management problems, and have economic, social and political 
costs, which will be unprecedented? What we need to do to put in this 
in context to understand it is to go back about 60 years, and our next 
chart helps us do that?
  This begins with the work of a Shell oil scientist by the name of M. 
King Hubbert. M. King Hubbert worked during the 1940s and 1950s. He was 
observing the exploitation and the exhaustion of oil fields. He noticed 
that each oil field followed what we call a bell curve, goes up steeper 
and steeper, finally reaches a peek, and then down the other side.
  He saw this in field after field. He rationalized if he could add up 
all the fields in the United States and guess as to how many more we 
were going to find, he could then estimate when the United States would 
peak in oil production. He made that estimate in 1956, and he said that 
the United States would peak in oil production about 1970.
  As it turned out, he was right on target. You can see here from the 
graph, this peak in 1970. The smooth curve here is his prediction. The 
more ragged curve, or the actual data points, and you see that right on 
target, it peaked in 1970.
  The red curve here is the curve for the Soviet Union, now Russia. 
They kind of fell apart with their dissolution, and they did not reach 
their potential, so there is going to be a second kind of a much lower 
short peak here. Russia has already peaked in their oil production.
  Mr. Speaker, more than half of all of the oil-producing countries in 
the world, some 25, I believe, have already peaked. Their peak oil 
production is already behind them. The next chart shows a schematic 
that helps us understand this, perhaps a little better.
  This represents a 2 percent exponential growth in oil. Now, all the 
oil that was produced was used. For the first part of the curve the 
production of oil and the use of oil are the same thing. Obviously, you 
are not going to produce oil that you do not use.
  If you need more oil, and it can be produced, your price indicators 
will mean that more oil is going to be produced. So for this part of 
the curve, we have used the oil as fast as we produced it.
  At some point in time, it will peak. It peaked for the United States 
in 1970. M. King Hubbert said it would peak for the world about now. 
Actually, he said a few years earlier, but he could not have known of 
the Arab oil embargo and the world oil price hike spikes which sent the 
world into a recession, which reduced the demand for oil. That moved 
the peak a little forward. We believe, many observers believe, that we 
are peaking about now, or will shortly be peaking.
  Mr. Speaker, I hope that the message that is in this document, 
peaking of world oil production, and the things that I am going to say, 
I hope they are wrong. Because if they are not wrong, we in United 
States and the world is in for a very rough ride. By the way, we can 
make this a very sharp peak or a very gradual one, by simply changing 
the scale on the abscissa and the ordinate. This represents a 2 percent 
increase in oil use.
  It is 2 percent of what it was last year, so it keeps growing, it 
grows what we call exponentially. With a 2 percent growth, it doubles 
in 35 years. Since this point is half of that point on the ordinate 
scale, this represents 35 years.

                              {time}  2100

  So you see that some years before we actually reach peak, and we 
believe that we may be here at this point, but a few years before you 
reach peak, you actually are not producing as much as you would like to 
use. Just a very few years ago in 1998, I think, oil was under $10 a 
barrel, and now it was about $60 a barrel. So, clearly, there is not as 
much there as the world would like to

[[Page 26517]]

use; and because there is not as much there, there is a higher demand 
for it, and so the price goes up.
  We will be talking this evening about filling the gap. This is the 
gap we are talking about filling here. What are we going to do now that 
we have reached this point? There are two things we can do. One of them 
is simply reduce our consumption of oil so that there is enough to go 
around, and the other is to try to find some other source of energy so 
we can fill this growing gap; and the further out we go, you will see 
the bigger the gap gets. We will be talking about that a little later.
  The next chart is an interesting one that shows the relationship 
between the oil we found and the oil we used. This is the difference 
between the oil we found and the oil we used. You see this is about the 
year 1980. Up until about 1980, every year we found more oil than we 
used. So we were accumulating an excess. This much excess was 
accumulated. From about 1980 on, we did not find as much oil as we 
used; and so to have enough oil available, we had to now start pumping 
our reserves. And so since 1980 our reserves have been going down and 
down because we have never, I think, in any year since about 1980 found 
as much oil as we pumped.
  The next chart shows these relationships in a somewhat different way 
that may be a little easier to understand. Here we have these bars and 
they represent, you see that was very similar to the previous chart, 
and this shows the actual discovery of oil. This does not subtract what 
we use from what we found because we have a second curve here, which is 
the use curve, and you will see this black curve here. That is the 
amount of oil that we have used.
  Now, it is very obvious that you cannot pump oil that you have not 
found. So if you kind of round this curve out and you get a curve here 
that has an area under it, that is the amount of oil that we can use. 
The amount that we have used is under this curve here. And since about 
1980 we have had to make up for what we did not find by borrowing from 
that which we had found. So you are going to have to borrow some of 
this and fill in this space here to get us to where we are now in 2005.
  Where do we go from here? Well, where we go from here is going to be 
determined by how much of this oil that we found is still available and 
how much more oil we are going to find.
  Now, the people who put this graph together guessed that the oil 
could keep going down because it has been going down for 20 years. See 
the slope down for about 20 years? They guessed it would keep on going 
down at that slope. So the amount of oil we can use in the future is 
going to be the difference between what we find, which they think is 
going to be less and less each year which I am sure it will be because 
it has been for the last two decades, and the amount of oil that we 
use, and that will be made up by the oil that is here.
  So you can draw very many curves that do not have you falling off a 
cliff. And clearly the wells do not perform the way that you pump full 
bore and you get the last drop out and you do not get any the next day. 
It tapers off little by little as you come down what is called 
Hubbert's peak.
  The next chart is from the Hirsch Report, and in this chart he has 
simplified Hubbert's peak. And for purposes of their presentation here, 
they have depicted Hubbert's peak as not being the bell curve that we 
looked at before, but as simply being a slope up and they slope down. 
And they will tell you in the report that they have simplified that 
because of the points that they want to make later.
  The bottom of the chart here shows something very interesting. It 
shows our production of oil in our country peaking in 1970. After 1970, 
we have developed some really good techniques for improving the 
discovery of oil and the recovery of oil.
  Mr. Speaker, really big increases in our technologies for both 
finding oil and for pumping it, enhanced recovery of oil, did not make 
any appreciable difference in the amount of oil that we were able to 
pump. This points to the fact that the geology really determines how 
much oil we are going to get in the enhanced recovery techniques, and 
the field exploration techniques do not make much difference.
  Another thing that does not make much difference at all is price. We 
are falling down the slope here. Notice what happened to price. It went 
way up. That ought to have resulted, if you think the marketplace 
works, that ought to have resulted in a lot more oil production in our 
country. It did not.
  You see, nothing really happened to the oil production when the price 
really spiked here. But what this graph does is to make the point that 
increased technologies and increased price will have little effect on 
the production of oil from a field that has already peaked and you are 
going down slope.
  The next chart is an interesting one, and what this shows is kind of 
what was shown in the past one, perhaps in a more dramatic way. By 1980 
we were already 10 years down the other side of what was called 
Hubbert's peak, and the Reagan administration noted that and they knew 
they needed to have more oil. Their solution to that was to incent our 
oil companies to go out and drill more, so they provided some tax 
incentives for that, and it really worked because this is the drill 
here you see. And it really spiked after 1980; they drilled a lot more 
wells.
  But notice this relationship between the oil that you have found and 
the oil you are pumping; and in spite of all that drilling, we went 
negative. What that shows is if it is not there, you cannot drill it. 
No matter how many holes you drill, you will not get more oil if there 
is not more oil there to get.
  The next chart is kind of a blow-up of the situation in our country 
since 1935 to roughly the present. This shows where we have gotten our 
oil from. It shows us peaking in 1970. Oil from Texas, the rest of the 
United States, the natural gas liquids, and then the big discovery of 
oil in Prudhoe Bay. We were already slipping down Hubbert's peak. There 
was a little blip there as we slipped down Hubbert's peak. But notice 
this source where we are getting 25 percent of our oil really did not 
stop us from slipping down Hubbert's peak.
  Notice the yellow there, Mr. Speaker. That is the fabled Gulf of 
Mexico oil discovery. You may remember that. A number of years ago that 
was supposed to solve our problem. It was oil for the foreseeable 
future. That is all the contribution it made.
  Now, we clearly have been using more oil since we peaked, and we have 
been getting it from overseas; and we now get nearly two-thirds of our 
oil from overseas because, Mr. Speaker, we have only about 2 percent of 
the known reserves of oil in the world. We use about 25 percent of the 
world's oil, and we import about two-thirds of what we use.
  The next chart shows the estimate of a number of authorities on when 
peaking is going to occur. Here we have the dates, and this first block 
of dates are those between now and 2010. That is pretty soon. You see 
the individuals there. Several of those I know personally. Colin 
Campbell, I have talked with him on the phone from over in the British 
Isles. Matt Simmons is the personal energy adviser of the President, 
president and CEO of perhaps the largest energy investment bank in the 
world. Dr. Deffeyes is a professor at Princeton University who has 
written a book on this subject, ``The End of Oil,'' I think, ``The View 
From Hubbert's Peak'' is what he calls it. Then we have a few who think 
the peak is going to be between 2010 and 2015. And then there are three 
that say that it is going to be there at notice.
  Mr. Speaker, there is no argument that there will be a peak except 
for the last one here, Lynch, who believes it will be a long plateau. 
He is not arguing that it will not peak, but he thinks it will not 
reach the top and fall off. It will be a long plateau.
  I would like to note, Mr. Speaker, that the economists here tend to 
be those that think that peak will be sometime in the future. What 
economists do is simply predict the future from the past. They are very 
good at studying the past. And if, in fact, there are inexhaustible 
resources, it is very logical that you ought to be able to predict the 
future from the past. But if,

[[Page 26518]]

in fact, there is a limited supply of oil, then you may not be able to 
predict the future from the past. But notice the big group of experts, 
and this is who they work for and what they are, and notice several of 
them are retired.
  We find when a military person takes off their uniform, we sometimes 
get kind of different testimony from them than when they wear the 
uniform. These people do not have any company they are accountable to. 
They are retired. For people who are just retired, Mr. Speaker, you 
tend to get very honest testimony from them. So you know who they are 
and who they work for and they are very credible people and they are 
pretty much all saying that peaking is pretty soon.
  The next chart shows how we use the oil that we get. The big blue on 
top here is transportation. That is where we use about 70 percent of 
it. The yellow is industrial. The purple down here is electric power, 
and then what we use in our homes, residential, and then commercial at 
the very bottom.
  The important part of this is the transportation, important for two 
reasons. One is that it is the biggest chunk of it and, secondly, it is 
that use of oil that cannot be readily replaced by something else. In 
industry they can use energy from many other sources for much that they 
do; but for transportation, we are pretty much stuck with oil.
  The next chart shows us some of the characteristics of the fuels that 
we use and this is talking about energy density, how many gigajoules 
you get per ton. Gigajoules is a technical term. It simply means BTUs 
or calories or heat or energy that you get from a given volume of this. 
We tend to think of it in gallons or barrels, 42 gallons in a barrel by 
the way.
  Here you see that crude oil is here at 449, and then diesel 
automotive as you start to refine it you get higher and higher 
densities.
  Now, as we run down Hubbert's peak and start running low on oil and 
still want to drive our cars and our planes and so forth, we will have 
to find a substitute. Notice that the substitutes here have very much 
less energy density. I would like to spend just a moment, Mr. Speaker, 
talking about energy density because it is really very important and 
presents a big challenge to us.
  One barrel of oil, that is 42 gallons of oil, the refined product of 
which you can buy now for just a tenth of a penny under $2 at some 
stores now. So you can buy it for well less than $100. That will buy 
you the work output of 12 people working all year for you.
  If you have some trouble getting your arms around that, Mr. Speaker, 
just imagine how far that gallon of gas or diesel fuel takes your 
pickup truck or your SUV or your car. By the way, that is still cheaper 
than water in the grocery store if you are buying it in the small 
bottles.
  Now, you could pull your car or truck or SUV as far as that gallon of 
fuel takes you, how long would it take you to pull your truck there. 
Obviously, you cannot pull it, but you can use a come-along and guard 
rails and trees and so forth, and by and by you will get it there. But 
it would take you quite a while to take it the distance that that one 
gallon takes you.
  Another little example of this energy density and the tremendous 
challenge we face of finding something that is equivalent to this: If 
you work all day real hard in your yard this weekend, I will get more 
work out of an electric motor with less than 25 cents worth of 
electricity.

                              {time}  2115

  That may be kind of humbling to recognize that in terms of fossil 
fuel energy we are worth less than 25 cents a day, but this incredible 
wealth that we found under the ground, how fast we have used it. How 
little concern we show for the future.
  The next chart addresses the transportation challenge we have. 
Obviously, the oil will go further if we are using less of it, but what 
he says here is that we cannot conceive of any affordable, government-
sponsored crash program to accelerate normal replacement schedules for 
our cars and trucks. The average car is on the road I think 16 years. 
That is the median. That does not mean it is the average because the 
last one is 18 years, that is the middle one, and the average light 
truck, about the same distance, 16 or 17 years. The average big truck, 
heavy truck, is on the road for 28 years.
  So if you want to buy a Prius or an Insight or one of these hybrid 
cars now, we ought to be doing that. I am not discouraging us doing 
that. That will make a very small dent in oil use because the things 
that were bought just this year are going to be on the road 16 or 17 
years for cars and light trucks and 28 years median for heavy trucks. 
So it will take a long time.
  If you want to dramatically reduce oil use, you have got to get these 
gas hogs off the road and get some fuel efficient things on the road. 
What they are saying is they cannot conceive of any affordable here, 
and that is the key word here. Obviously, we could bribe all the people 
in the country to take their SUVs to the junkyard and give them enough 
money to get a new hybrid. That would not be affordable. That is the 
key word here.
  What he is pointing out here is it is going take a long time to make 
this change from our present gas guzzling SUVs, big cars and trucks and 
so forth and go to these hybrids.
  The next chart shows us the contribution that enhanced oil recovery 
can make. We have some really good techniques today, and some people 
will tell you do not worry. We are really good at getting oil out of 
the ground now, so do not worry about this peak. What this shows is it 
does not affect the peak. Indeed, if you think about it, it should not 
affect the peak, because up until this peak, the oil comes out of the 
ground easily. You do not need the enhanced recovery techniques to get 
it out because it comes out very easily anyhow. When you really need 
them is on the down slope, and this shows you get a little more oil out 
on the down slope.
  The next chart shows a depiction that the authors use, and this is 
really a simplification. They will tell you that this should be a 
growth curve here, an exponential curve, but they are making it a wedge 
because it helps them to make their points. And this is a schematic one 
for any substitute that you want to have.
  It takes awhile before you get anything out of it. You have got to 
build the plant and plan, and then you start producing some of whatever 
this is. The next chart will show us the variety of things that it is, 
and the longer you have, the more and more of it you produce a day, 
present this thing as a wedge.
  The next chart shows us an addition of some of wedges that you might 
use to have more liquid fuels available.
  Enhanced oil recovery, we looked at that. That will produce 
something.
  Coal liquids. When I was a little boy, in our lamps we used coal oil. 
By and by that was substituted by kerosene, and Hitler ran his military 
in World War II on oil made from coal because he did not have any oil 
and we were not going to let him get any. So he had to make it from 
coal. They had a lot of coal.
  Heavy oil. Heavy oil is what determines why it is heavy. It will most 
likely sink in water some of it. All the rest of oil floats on water, 
and some of it is what is called sour. When you see that sour crude, 
light sweet crude is the most valuable. Sour crude has a lot of sulfur 
in it. You have to take that sulfur out. You are really polluting the 
air.
  Then gas to liquids, and then he shows something about efficient 
vehicles. It takes a while before you get this in the fleet, and notice 
in 15 years the trifling contribution that efficient vehicles have 
made.
  The next chart is a composite here that makes a salient point that 
they make in their paper, and here they look at three different 
scenarios of when you start to address the problem and the consequences 
of that.
  The first of these, you start your crash program when you peak out. 
You say, gee, we cannot get as much oil out of the ground today as we 
got yesterday. That will not literally be true. It will be this month 
compared to last

[[Page 26519]]

month because day-to-day is probably not going to make that big a 
difference.
  If you wait until you see peak oil, what they are saying here is that 
run as fast as you can. With mitigation, you are still going to have a 
big shortfall.
  By the way, I would like to refer back to their simplification of the 
bell curve. They simply use a slope up and a slope down, and what they 
are saying here, when you reach peak oil, you would really like to keep 
on going and use more and more. This really, of course, is an 
exponential curve going up, but they show here for simplicity a 
straight line and what they are trying to do is fill the gap. I am 
going to come back to that in a couple of minutes, but I am not sure we 
ought to be trying to fill the gap.
  The second curve here represents what happens if you anticipate it by 
10 years, and notice that most of the people in that former chart 
thought you were going to have peak oil a lot sooner than 10 years from 
now, but if you have 10 years and start the mitigation, you are still 
going to have a shortfall. To have no economic consequences, they say 
they are going to have to start 20 years ahead.
  Now, almost nobody believes that we have 20 years ahead. So 
obviously, if we are trying to fill that gap, there is going to be some 
shortfall because it is either upon us or will shortly be upon us.
  I would like to talk for just a moment about whether or not we ought 
to try to fill that gap. For two reasons I think that maybe we ought to 
be considering that that is not really a good idea.
  One is there is a pretty widespread belief that the warm weather we 
are having and the more frequent and intense hurricanes, the melting of 
the icecaps and the glaciers may be due to global warming that may have 
resulted from an increase in greenhouse gases which are produced by 
burning these fossil fuels. Now, if that is true and you believe that 
is going to have a negative effect on our environment, our climate and 
so forth, which will ultimately affect us economically, then I am 
wondering why you would want to have more of this by trying to fill 
that gap.
  Let me give you another maybe even better reason that you should not 
be thinking about filling the gap.
  There is an old saying that if you are in a hole, stop digging. Now, 
a corollary to that would be, in this case, that if you are climbing a 
cliff, a hill, where you will come to a precipice and by and by fall 
off and have to uncomfortably go down the other side, the higher you 
climb, the further you have to fall. That is very germane to this 
because the more oil that we use, the more energy that we use, the 
higher we will have climbed up that cliff and the steeper will be the 
descent down the other side.
  The next chart, and you should notice, Mr. Speaker, the page where 
you can find these on each one. This is from page 64 of their report, 
and let me read this because this is really significant and I suspect 
that not too many people know this.
  World oil peaking is going to happen. That is a certainty. I think 
that everybody understands that oil cannot be forever. There is not an 
inexhaustible supply of oil. It is not going to last to forever. What 
does that mean?
  They think that it means that we will shortly peak in oil production. 
I would like to emphasize that peaking does not mean that we are going 
to run out of oil. We will not run out of oil for a long time, maybe 
100 years, but what we will have run out of is readily available, high 
quality oil that can be produced at the rate we would like to use it. 
It is oil peaking. It is not running out of oil.
  A hundred years from now there will be some oil, some gas, some coal, 
that we can find in ever-decreasing amounts at ever-increasing cost. It 
will not be very much in 100 years, but there will still be some.
  ``World production of conventional oil will reach a maximum and 
decline thereafter. That maximum is called the peak.''
  I would suggest, Mr. Speaker, that one can find a lot of information 
on this if you simply do a Google search for peak oil. Now, you get 
essentially the same information if you do a Google search for 
Hubbert's peak but peak oil will do. That is maybe easier to remember. 
You will find a lot of articles there relative to this.
  ``A number of competent forecasters,'' and we looked at that chart a 
few minutes ago, ``project peaking within a decade; others contend it 
will occur later. Prediction of the peaking is extremely difficult 
because of'' a number of things, ``geological complexities.''
  Let me pause just a moment to talk a little bit about the geology 
here and why you do not find oil everywhere.
  We believe that a very long time ago there were warm seas, and at 
that time, the world was warm up in northern Alaska and Siberia because 
there were warm seas there. In every sea there was life there that grew 
like algae on your pond. At the end of the season, it sank to the 
bottom, and then dirt was washed off of the adjoining hills and through 
a very long time that built up large deposits at the bottom of these 
warm seas.
  Then the tectonic plates of the earth separated. As you know, Mr. 
Speaker, there are tectonic plates that ride on the molten core of the 
Earth, and then the crust of the Earth is above those. These separated 
somewhat so that the bottom of these ancient warm seas were submerged, 
covered by a lot of rock and dirt. They were warm enough to the molten 
core of the Earth that it was just the right amount of heat. They were 
under enough pressure, and with time in this pressure cooker, this 
organic material was converted to oil and gas. Gas is the volatile part 
of this oil.
  Now, you do not only need that, Mr. Speaker, you need something else 
before you really have oil deposits and gas deposits. You need a dome 
of rock over top of this like a big umbrella that keeps the volatiles, 
the gas, from going up and escaping because, you see, if they can 
escape, you do not end up with the nice, light sweet crude oil that we 
value so much. You end up with something like the tar sands in the oil 
shales. It is a little bit like the asphalt roads you drive on.
  Now, if you cook that stuff, it will flow, and it is pretty much what 
these tar sands in oil shales are, something like that. So they were a 
very unique series of events that occurred that provide the oil and the 
gas for us, and it is no argument that you should not find it, probably 
are not going to find it everywhere in the world.
  By the way, when I was a little boy we lived near a coal mining town, 
and we got what was called Run-of-mine coal. In those days there was 
not a big mechanical thing on a coal face digging it off. It was a 
miner with a pick and his shovel and his wheelbarrow. He may have had a 
little cart and a mule inside the mine to help him in some of the 
bigger mines.
  But that would come out of the mine, and we would buy it just as it 
came out, called Run-of-mine, just the way you mined it, some big lumps 
on down to dust. Some of those big lumps were so big I could not put 
them in the furnace. So there was a sledge hammer, and we would have to 
break the lump to put it in the furnace. I remember breaking some of 
those lumps and they would fall open and there would be a fern leaf. I 
remember the thoughts that I had, gee, how long ago did that thing 
grow. It was very obvious where coal came from. You can see the 
vegetation inside the coal.
  ``Geological complexities, measurement problems, pricing variations, 
demand elasticity,'' how much of it we are going to need, ``and 
political influences,'' are they really going to sell us the oil or 
not. ``Peaking will happen, but the timing is uncertain.'' But the fact 
that it will peak is not uncertain. It will peak.
  ``Oil peaking presents a unique challenge,'' they say. Then I 
emphasize this statement. ``The world has never faced a problem like 
this. Without massive mitigation more than a decade before the fact, 
the problem will be pervasive and will not be temporary. Previous 
energy transitions, wood to coal and

[[Page 26520]]

coal to oil, were gradual and evolutionary; oil peaking will be abrupt 
and revolutionary.''

                              {time}  2130

  The next chart takes us back about 400 years in history. It would be 
nice to have one that took us back 5,000 years in history because that 
is about the extent of recorded history, about 5,000 years. But we go 
back here to the very beginning, a little bit before the beginning of 
the Industrial Revolution, and we notice that the Industrial Revolution 
began with wood and it ramped up, and we denuded largely the mountains 
of New England to make charcoal to take to England to make steel, and 
then we found coal. And the ordinate here is quadrillion BTUs. That was 
the amount of energy we got. Boy, did we get a lot more energy from 
coal than we did from wood. It is more dense. It is easier to get and 
haul large quantities of it. But notice what happened when we came to 
gas and oil. There was essentially an explosion in the amount of energy 
that we could produce. Notice up there at the top, Mr. Speaker, the 
recession of the 1970s produced by the Arab oil embargo.
  There is a stunning statistic. Up until the Carter years, every 
decade, the world used as much oil as had been used in all of previous 
history. Now what that means is that when we had used half of all the 
oil that was there, we would have only one decade of oil remaining. 
Now, that slowed down after the Arab oil embargo. We got a lot more 
efficient. The refrigerator we have today probably uses a third of the 
electricity it did then; so we really slowed down in our use of oil, or 
this chart curve would have kept on going up.
  There is another curve we might put on here, Mr. Speaker, and that is 
the world's population. And it might not be too surprising that the 
increase in population pretty much paralleled the increase in available 
energy. We started out with 1 billion, more or less, before the 
Industrial Revolution. Now we have almost 7 billion people.
  Mr. Speaker, in terms of 5,000 years of recorded history, the age of 
oil will be but a brief blip. We have been in the age of oil about 150 
years. It was about 150 years ago we first found oil in any quantities 
and started to use it. In another 150 years we will essentially be 
through the age of oil. What will our world look like when we have 
exhausted the fossil fuels? And they will be exhausted.
  One of the writers in writing about this says that our great 
grandchildren, in looking at history and what we did with these fossil 
fuels, will say how could the monsters have done that. How could they 
have found this incredibly valuable resource buried in the ground, 
these riches buried in the ground, and used them wantonly with no 
regard that they might be finite, that they would one day run out. Matt 
Savinar, who wrote one of the articles that people will find when they 
do the Google search for peak oil, Matt Savinar begins his article by 
saying: ``Dear reader, civilization as we know it is coming to an end 
soon.'' I pulled it off the Web and gave it to my wife, and she read 
that first paragraph and said, The guy is crazy; I am not going to read 
any more.
  I said, Please read on and reserve judgment.
  She read on and was genuinely frightened when she had finished his 
article. Matt Savinar may be audacious, and I think that the future may 
not be so bleak as he presents it, but I will tell the Members, Mr. 
Speaker, if we do not do something meaningful in terms of trying to 
mitigate the damage, it could be, it could be as bad as Matt Savinar 
presents it. He may be audacious, but he is not an idiot; and I would 
suggest that Members read his article. It is very useful.
  The next chart shows something really interesting that we have been 
talking about this evening. This is where we are now. We have been 
running up this side of Hubbert's peak. This, by the way, is worldwide. 
The question is now, When will the world do what the United States did 
in 1970? When will the world reach peak oil? I had a course in 
statistics when I was working for my doctorate in school maybe 55 or 60 
years ago, and what they have done here, we have a probability of 95 
percent. That is most likely what we will find. And then we have a 50 
percent probability that it could be higher or it could be lower and 
then a 5 percent probability or it could be higher or it could be 
lower, and somehow they mysteriously take this as the expected value. 
It could be low just as well as high. That is not the expected value. 
The value that the statistician would tell us to expect is a 95 percent 
value. And, by the way, that is pretty much what the experts tell us.
  A couple of Congresses ago, I was Chair of the Energy Subcommittee on 
the Science Committee, and I wanted to determine the dimensions of this 
problem. So we had a hearing and invited in the world's experts on oil 
reserves, and there was pretty unanimous agreement. I was surprised. It 
was somewhere like from 970 to 1,040, about 1,000 gigabarrels of oil 
that remained. Now, we have pumped about the same amount. We have 
pumped about 1,000 gigabarrels. That is 1,000 billion barrels. That is 
1 trillion barrels, and that sounds like a lot.
  But if we divide that 1,000 gigabarrels by the 84 million barrels 
that we use a day, 21 in our country alone, 63 in the rest of the 
world, 84 total, if we divide that 84 million barrels a day into the 1 
trillion barrels that the experts told us are still out there, we come 
to about 40 years' remaining oil. Remember up until the Carter years, 
when we used half of it, which is about what we have used, we would 
have only 10 years remaining; so we have really slowed down, 
fortunately. We are using it much more efficiently now than we did 
then.
  But they make two assumptions for this chart. One is that it peaks in 
2016 and that there is 3,000 gigabarrels. That is not what the experts 
say. The experts say that there will be a total of about 2,000 
gigabarrels, 1,000 already pumped, another 1,000 to be pumped. If that 
is true, then we would start downhill from this point.
  But if we have another 1,000 gigabarrels, notice with this 
exponential curve how little that pushes peak oil out. Not very far. 
What is it? About 2017, 2016, something like that is all that it pushes 
out. Here it is: 2016. And if we now assume that there is more than 
that, it pushes it out further. But notice what happens. Notice what 
happens. Notice how quickly we fall.
  I made the point before I am not sure we want to fill the gap because 
the analogy of if you are in a hole, stop digging is if you are 
climbing a hill and you are going to fall off a cliff on the other 
side, the lower the hill, the less you will fall. And they make exactly 
that point here in these predictions.
  These are predictions of the Energy Information Agency. These are 
economists working for the Department of Energy. They are not oil 
experts. They are economists, and they do what economists do. They 
predict the future from the past. And they really study the past and 
know it, and they think that if they know the past well, they can 
predict the future. But what they do not take into account is that oil 
is finite and their predictions would be exactly right if market forces 
controlled and if oil were limitless, but oil is clearly not limitless.
  In the last chart that I want to spend a few minutes on, where do we 
go from here? From where will we get our liquid fuels? From where will 
we get our energy as we run down the other side of Hubbert's peak? We 
have here some finite resources. By ``finite'' we mean they are not 
forever. Some of them are pretty big if we can get the energy out. Tar 
sands and oil shales. Some will tell us do not worry about the future 
of energy because there is 1\1/2\ trillion barrels of oil in the oil 
sands of Canada alone. That is true. But, Mr. Speaker, there is also an 
incredible amount of energy in the tides.
  I pick up two 5-gallon buckets of water, and they are pretty heavy; 
and then I note that the Moon lifts the whole ocean about 2 feet. That 
is an incredible amount of energy. But because there is that incredible 
amount of energy out there does not mean that I can harness it and use 
it effectively.

[[Page 26521]]

The same thing is pretty much true of these tar sands. Yes, there is 
potentially a lot of energy there, but how effectively, efficiently can 
we get it out?
  The Canadians are now producing oil maybe even less than $30 a 
barrel. They are selling for $60. That is a good deal, and they are 
producing a lot of it. But when we look at the energy that it takes to 
get it out, there are better techniques than the one they are using; 
but the technique they are using, they use more energy from natural gas 
than they get out of oil so that the energy profit ratio is less than 
nothing. The oil is sought on the market and brings a good price. The 
gas is up there and they do not need it and it is hard to ship. So from 
a dollar-and-cents perspective, it may make sense to use that gas, even 
more energy and gas to produce the oil than they get out of the oil. 
But ultimately, of course, as we move to a more energy-efficient world, 
we will not be able to do that.
  I was out at a conference in Denver, Colorado, just this past 
weekend; and the Shell Oil scientist that was doing some of the tests 
in the oil shales of Colorado emphasized that his work was just 
experimental, that he could not extrapolate from what he had now done 
to the future. And what they have done is kind of interesting, Mr. 
Speaker.
  They have taken a small patch of Colorado desert out there, high 
desert, and they have drilled a lot of holes in a circle and frozen, 
put pipes down there, and they froze in the ground. What they have done 
is to make a vessel out of frozen ground because they do not want what 
they are doing inside that big vessel to contaminate groundwater 
outside, and then they cook the oil.
  I hear from 2 years to 4 years, for some period of time, they cook 
the oil inside that vessel. They keep putting hot water down there, 
steam down there, and they cook the oil. By the way, they heat that 
with natural gas, which is why it takes so much energy. And then they 
pump on that. When they have heated it up, it will flow so they can 
pump it out. But this is pretty small. It is hard to scale up from 
that. And they put in one unit of energy from heat and they get out 
3\1/2\ units of energy. That looks like a pretty good energy profit 
ratio, but it does not account for all the energy that goes in there: 
drilling the holes and refrigeration and the energy it took to make the 
equipment that they use and refining it when they get it out and so 
forth.
  So we are not yet sure how positive that is going to be. It may be 
that we will use the energy from four barrels of oil and have one net 
plus.
  By the way, that would not be all that bad because that is about the 
ratio in producing ethanol. We have to put in about three-fourths as 
much energy into the ethanol as we get out of it, about 750,000 BTUs of 
energy to get 1 million units of energy in producing ethanol; and that 
is for efficient production. Many of our ethanol production facilities 
now are producing ethanol, Dr. Pimental believes, with a negative 
energy profit ratio: the more fossil fuel energy goes in to producing 
it than we get out of it.
  Coal: we have about 250 years of coal remaining in our country. That 
is the current use rate. If we increase the use only 2 percent 
exponentially, that 250 years shrinks to 85 years. For many uses like 
our car, we cannot use coal. We are going to have to use gas or a 
liquid, and we are going to have to take some energy to make that 
conversion. Now it shrinks to 50 years. So we have got about 50 years 
of effective coal remaining at only a 2 percent increase. We may need 
to increase its use much more than 2 percent. It is there. We need to 
husband it and use it wisely.
  Nuclear: we produce 8 percent of our electricity in this country from 
nuclear. That is 20 percent of our electricity.

                              {time}  2145

  That can and maybe should grow. But the kind of plants we use, the 
light water reactor plants, cannot be expanded indefinitely because 
there is a limited supply of fissionable uranium in the world. I get 
wildly divergent estimates, from 30 years to 200 years. That is at 
current-use rates. As soon as you start exponentially increasing the 
rate of use, whatever that time is, it shrinks very rapidly.
  That means if we really wanted to go big-scale nuclear, we need to go 
to breeder reactors. With breeder reactors, you borrow a lot of 
problems, like transporting the fuel for enrichment. You have weapons-
grade plutonium produced, and you may in the future be making a choice 
between buying these problems and shivering in the dark because in an 
energy-deficient world, that may be the choice that you come to.
  Nuclear fusion. Oh, how I hope we get there because then we are home-
free. But planning to solve our energy problems in this country of the 
world with fusion is a bit like you or me planning to solve our 
personal economic problems by winning the lottery. It would be nice if 
it happened; it probably will not, and I certainly would not count on 
it.
  And then we come to the truly renewable sources. About half of those, 
a little more than half comes from nuclear up here as compared to what 
is down here. Solar, wind, they now represent about a quarter of a 
percent of our total energy. A bit more than that of electricity, but 
about a quarter of a percent of our total electricity.
  Geothermal, that is tapping into the molten core of the earth. Where 
we can do that, we ought to do it because that will last a very long 
time.
  I mentioned ocean energy. Lots of energy there. The tides, the waves, 
thermal gradients in the ocean. There is a lot of potential energy 
there, but there is an old axiom that says energy to be effective must 
be concentrated. It is so diffuse in the ocean. We have been trying for 
a very long time to capture some of that energy, and it is very, very 
difficult.
  And then we come to agricultural resources. A lot of people have high 
hopes for what we can get from agriculture. We can get energy from 
agriculture in two different ways: One by producing fuels like ethanol 
and methanol by fermenting the product; and the other is by burning the 
product.
  There are limits to both of these. We now are barely able to feed the 
world. Tonight a fair number of people will go to bed hungry. We could 
free up more of this energy if we would be content to eat the soybeans 
and corn rather than the pig and the cow and the chicken eating the 
corn and the soybeans.
  To take biomass from the soil, that is what makes topsoil different 
from subsoil is organic material, biomass. I am sure we can get some 
energy from that. But we have to be careful how much to tend to get 
from that.
  Waste energy, instead of putting it in the landfill, burn it. There 
is a really good plant here in Montgomery County very near. I would be 
proud to have that next to my church. I cannot even see that it is 
burning trash because trash comes in inside a big container. It is 
inside before it is emptied, and it looks like a nice brick office 
building.
  The last thing is hydrogen from renewables. Hydrogen is not an energy 
source. You cannot mine it or suck it out of the air. The only way you 
get hydrogen is to use energy from some other source like natural gas. 
This is where we get most of it or like splitting water with 
electrolysis. You will always use more energy in getting the hydrogen 
than you get out of hydrogen, or else you are going to have to repeal 
the second law of thermodynamics, and that is not going to happen. It 
is still a good idea because hydrogen burns very cleanly. You get only 
water. You can burn it in a fuel cell where you have at least twice the 
efficiency of reciprocating engine, but it is not a solution to our 
energy problem. Think of it as an energy carrier which is exactly what 
your battery is.
  If you think of this as being a hydrogen battery as opposed to an 
electron battery that you have in your car, you will get it right as 
far as hydrogen is concerned.
  There is a lot of talk about a hydrogen future. That is not going to 
happen in the next decade or two or even three. It is going to take a 
very long time to ramp up, and we will always have to have some bigger 
energy source

[[Page 26522]]

from which we make the hydrogen because it will always be made with an 
energy deficit because we are not going to repeal the second law of 
thermodynamics.
  Mr. Speaker, I want to submit for the Record this report because it 
is not available anywhere else for the public to review.

Peaking of World Oil Production: Impacts, Mitigation, & Risk Management

(By Robert L. Hirsch, SAIC, Project Leader; Roger Bezdek, MISI; Robert 
                            Wendling, MISI)

                             February 2005


                               DISCLAIMER

       This report was prepared as an account of work sponsored by 
     an agency of the United States Government. Neither the United 
     States Government nor any agency thereof, nor any of their 
     employees, makes any warranty, express or implied, or assumes 
     any legal liability or responsibility for the accuracy, 
     completeness, or usefulness of any information, apparatus, 
     product, or process di1losed, or represents that its use 
     would not infringe privately owned rights. Reference herein 
     to any specific commercial product, process, or service by 
     trade name, trademark, manufacturer, or otherwise does not 
     necessarily constitute or imply its endorsement, 
     recommendation, or favoring by the United States Government 
     or any agency thereof. The views and opinions of authors 
     expressed herein do not necessarily state or reflect those of 
     the United States Government or any agency thereof.

                           Table of Contents

       Executive Summary
       I.  Introduction
       II.  Peaking of World Oil Production
       III.  Why Transition Will Be Time Consuming
       IV.  Lessons From Past Experience
       V.  Learning From Natural Gas
       VI.  Mitigation Options & Issues
       A.  Conservation
       B.  Improved Oil Recovery
       C.  Heavy Oil and Oil Sands
       D.  Gas-To-Liquids
       E.  Liquids from U.S Domestic Sources
       F.  Fuel Switching to Electricity
       G.  Other Fuel Switching
       H.  Hydrogen
       I.  Factors That Can Cause Delay
       VII.  A World Problem
       VIII.  Three Scenarios
       IX.  Market Signals as Peaking Is Approached
       X.  Wild Cards
       XI.  Summary and Concluding Remarks
       Appendices

                           Executive Summary

       The peaking of world oil production presents the U.S. and 
     the world with an unprecedented risk management problem. As 
     peaking is approached, liquid fuel prices and price 
     volatility will increase dramatically, and, without timely 
     mitigation, the economic, social, and political costs will be 
     unprecedented. Viable mitigation options exist on both the 
     supply and demand sides, but to have substantial impact, they 
     must be initiated more than a decade in advance of peaking.
       In 2003, the world consumed just under 80 million barrels 
     per day (MM bpd) of oil. U.S. consumption was almost 20 MM 
     bpd, two-thirds of which was in the transportation sector. 
     The U.S. has a fleet of about 210 million automobiles and 
     light trucks (vans, pick-ups, and SUVs). The average age of 
     U.S. automobiles is nine years. Under normal conditions, 
     replacement of only half the automobile fleet will require 
     10-15 years. The average age of light trucks is seven years.
       Under normal conditions, replacement of one-half of the 
     stock of light trucks will require 9-14 years. While 
     significant improvements in fuel efficiency are possible in 
     automobiles and light trucks, any affordable approach to 
     upgrading will be inherently time-consuming, requiring more 
     than a decade to achieve significant overall fuel efficiency 
     improvement.
       Besides further oil exploration, there are commercial 
     options for increasing world oil supply and for the 
     production of substitute liquid fuels: (1) Improved Oil 
     Recovery (IOR) can marginally increase production from 
     existing reservoirs; one of the largest of the IOR 
     opportunities is Enhanced Oil Recovery (EaR), which can help 
     moderate oil production declines from reservoirs that are 
     past their peak production; (2) Heavy oil/oil sands 
     represents a large resource of lower grade oils, now 
     primarily produced in Canada and Venezuela; those resources 
     are capable of significant production increases; (3) Coal 
     liquefaction is a well established technique for producing 
     clean substitute fuels from the world's abundant coal 
     reserves; and finally, (4) Clean substitute fuels can be 
     produced from remotely located natural gas, but exploitation 
     must compete with the world's growing demand for liquefied 
     natural gas. However, world-scale contributions from these 
     options will require 10-20 years of accelerated effort.
       Dealing with world oil production peaking will be extremely 
     complex, involve literally trillions of dollars and require 
     many years of intense effort. To explore these complexities, 
     three alternative mitigation scenarios were analyzed: 
     Scenario I assumed that action is not initiated until peaking 
     occurs. Scenario II assumed that action is initiated 10 years 
     before peaking. Scenario III assumed action is initiated 20 
     years before peaking.
       For this analysis estimates of the possible contributions 
     of each mitigation option were developed, based on an assumed 
     crash program rate of implementation.
       Our approach was simplified in order to provide 
     transparency and promote understanding. Our estimates are 
     approximate, but the mitigation envelope that results is 
     believed to be directionally indicative of the realities of 
     such an enormous undertaking. The inescapable conclusion is 
     that more than a decade will be required for the collective 
     contributions to produce results that significantly impact 
     world supply and demand for liquid fuels.
       Important observations and conclusions from this study are 
     as follows:
       1. When world oil peaking will occur is not known with 
     certainty. A fundamental problem in predicting oil peaking is 
     the poor quality of and possible political biases in world 
     oil reserves data. Some experts believe peaking may occur 
     soon. This study indicates that ``soon'' is within 20 years.
       2. The problems associated with world oil production 
     peaking will not be temporary, and past ``energy crisis'' 
     experience will provide relatively little guidance. The 
     challenge of oil peaking deserves immediate, serious 
     attention, if risks are to be fully understood and mitigation 
     begun on a timely basis.
       3. Oil peaking will create a severe liquid fuels problem 
     for the transportation sector, not an ``energy crisis'' in 
     the usual sense that term has been used.
       4. Peaking will result in dramatically higher oil prices, 
     which will cause protracted economic hardship in the United 
     States and the world. However, the problems are not 
     insoluble. Timely, aggressive mitigation initiatives 
     addressing both the supply and the demand sides of the issue 
     will be required.
       5. In the developed nations, the problems will be 
     especially serious. In the developing nations peaking 
     problems have the potential to be much worse.
       6. Mitigation will require a minimum of a decade of 
     intense, expensive effort, because the scale of liquid fuels 
     mitigation is inherently extremely large.
       7. While greater end-use efficiency is essential, increased 
     efficiency alone will be neither sufficient nor timely enough 
     to solve the problem. Production of large amounts of 
     substitute liquid fuels will be required. A number of 
     commercial or near-commercial substitute fuel production 
     technologies are currently available for deployment, so the 
     production of vast amounts of substitute liquid fuels is 
     feasible with existing technology.
       8. Intervention by governments will be required, because 
     the economic and social implications of oil peaking would 
     otherwise be chaotic. The experiences of the 1970s and 1980s 
     offer important guides as to government actions that are 
     desirable and those that are undesirable, but the process 
     will not be easy.
       Mitigating the peaking of world conventional oil production 
     presents a classic risk management problem: Mitigation 
     initiated earlier than required may turn out to be premature, 
     if peaking is long delayed. If peaking is imminent, failure 
     to initiate timely mitigation could be extremely damaging.
       Prudent risk management requires the planning and 
     implementation of mitigation well before peaking. Early 
     mitigation will almost certainly be less expensive than 
     delayed mitigation. A unique aspect of the world oil peaking 
     problem is that its timing is uncertain, because of 
     inadequate and potentially biased reserves data from 
     elsewhere around the world. In addition, the onset of peaking 
     may be obscured by the volatile nature of oil prices. Since 
     the potential economic impact of peaking is immense and the 
     uncertainties relating to all facets of the problem are 
     large, detailed quantitative studies to address the 
     uncertainties and to explore mitigation strategies are a 
     critical need.
       The purpose of this analysis was to identify the critical 
     issues surrounding the occurrence and mitigation of world oil 
     production peaking. We simplified many of the complexities in 
     an effort to provide a transparent analysis. Nevertheless, 
     our study is neither simple nor brief. We recognize that when 
     oil prices escalate dramatically, there will be demand and 
     economic impacts that will alter our simplified assumptions. 
     Consideration of those feedbacks will be a daunting task but 
     one that should be undertaken.
       Our study required that we make a number of assumptions and 
     estimates. We well recognize that in-depth analyses may yield 
     different numbers. Nevertheless, this analysis clearly 
     demonstrates that the key to mitigation of world oil 
     production peaking will be the construction of a large number 
     of substitute fuel production facilities, coupled to 
     significant increases in transportation fuel efficiency. The 
     time required to mitigate world oil production peaking is 
     measured on a decade time-scale. Related production facility 
     size is large and capital intensive. How and when governments 
     decide to address these challenges is yet to be determined.
       Our focus on existing commercial and near-commercial 
     mitigation technologies illustrates that a number of 
     technologies are

[[Page 26523]]

     currently ready for immediate and extensive implementation. 
     Our analysis was not meant to be limiting. We believe that 
     future research will provide additional mitigation options, 
     some possibly superior to those we considered. Indeed, it 
     would be appropriate to greatly accelerate public and private 
     oil peaking mitigation research. However, the reader must 
     recognize that doing the research required to bring new 
     technologies to commercial readiness takes time under the 
     best of circumstances. Thereafter, more than a decade of 
     intense implementation will be required for world scale 
     impact, because of the inherently large scale of world oil 
     consumption.
       In summary, the problem of the peaking of world 
     conventional oil production is unlike any yet faced by modern 
     industrial society. The challenges and uncertainties need to 
     be much better understood. Technologies exist to mitigate the 
     problem. Timely, aggressive risk management will be 
     essential.

                            I. Introduction

       Oil is the lifeblood of modern civilization. It fuels the 
     vast majority of the world's mechanized transportation 
     equipment--Automobiles, trucks, airplanes, trains, ships, 
     farm equipment, the military, etc. Oil is also the primary 
     feedstock for many of the chemicals that are essential to 
     modern life. This study deals with the upcoming physical 
     shortage of world conventional oil--an event that has the 
     potential to inflict disruptions and hardships on the 
     economies of every country.
       The earth's endowment of oil is finite and demand for oil 
     continues to increase with time. Accordingly, geologists know 
     that at some future date, conventional oil supply will no 
     longer be capable of satisfying world demand. At that point 
     world conventional oil production will have peaked and begin 
     to decline.
       A number of experts project that world production of 
     conventional oil could occur in the relatively near future, 
     as summarized in Table I-1. Such projections are fraught with 
     uncertainties because of poor data, political and 
     institutional self-interest, and other complicating factors. 
     The bottom line is that no one knows with certainty when 
     world oil production will reach a peak, but geologists have 
     no doubt that it will happen.

         TABLE I-1.--PREDICTIONS OF WORLD OIL PRODUCTION PEAKING
------------------------------------------------------------------------
              Projected date                    Source of projection
------------------------------------------------------------------------
2006-2007.................................  Bakhitari
2007-2009.................................  Simmons
After 2007................................  Skrebowski
Before 2009...............................  Deffeyes
Before 2010...............................  Goodstein
Around 2010...............................  Campbell
After 2010................................  World Energy Council
2010-2020.................................  Laherrere
2016......................................  EIA (Nominal)
After 2020................................  CERA
2025 or later.............................  Shell
No visible Peak...........................  Lynch
------------------------------------------------------------------------

       Our aim in this study is to summarize the difficulties of 
     oil production forecasting; identify the fundamentals that 
     show why world oil production peaking is such a unique 
     challenge; show why mitigation will take a decade or more of 
     intense effort; examine the potential economic effects of oil 
     peaking; describe what might be accomplished under three 
     example mitigation scenarios; and stimulate serious 
     discussion of the problem, suggest more definitive studies, 
     and engender interest in timely action to mitigate its 
     impacts.
       In Chapter II we describe the basics of oil production, the 
     meaning of world conventional oil production peaking, the 
     challenge of making accurate forecasts, and the effects that 
     higher prices and advanced technology might have on oil 
     production.
       Because of the massive scale of oil use around the world, 
     mitigation of oil shortages will be difficult, time 
     consuming, and expensive. In Chapter III we describe the 
     extensive and critical uses of U.S. oil and the long economic 
     and mechanical lifetimes of existing liquid fuel consuming 
     vehicles and equipment.
       While it is impossible to predict the impact of world oil 
     production peaking with any certainty, much can be learned 
     from past oil disruptions, particularly the 1973 oil embargo 
     and the 1979 Iranian oil shortage, as discussed in Chapter 
     IV. In Chapter V we describe the developing shortages of U.S. 
     natural gas, shortages that are occurring in spite of 
     assurances of abundant supply provided just a few years ago. 
     The parallels to world oil supply are disconcerting.
       In Chapter VI we describe available mitigation options and 
     related implementation issues. We limit our considerations to 
     technologies that are near ready or currently commercially 
     available for immediate deployment. Clearly, accelerated 
     research and development holds promise for other options. 
     However, the challenge related to extensive near-term oil 
     shortages will require deployment of currently viable 
     technologies, which is our focus.
       Oil is a commodity found in over 90 countries, consumed in 
     all countries, and traded on world markets. To illustrate and 
     bracket the range of mitigation options, we developed three 
     illustrative scenarios. Two assume action well in advance of 
     the onset of world oil peaking--in one case, 20 years before 
     peaking and in another case, 10 years in advance. Our third 
     scenario assumes that no action is taken prior to the onset 
     of peaking. Our findings illustrate the magnitude of the 
     problem and the importance of prudent risk management.
       Finally, we touch on possible market signals that might 
     foretell the onset of peaking and possible wildcards that 
     might change the timing of world conventional oil production 
     peaking. In conclusion, we frame the challenge of an unknown 
     date for peaking, its potentially extensive economic impacts, 
     and available mitigation options as a matter of risk 
     management and prudent response. The reader is asked to 
     contemplate three major questions: What are the risks of 
     heavy reliance on optimistic world oil production peaking 
     projections? Must we wait for the onset of oil shortages 
     before actions are taken? What can be done to ensure that 
     prudent mitigation is initiated on a timely basis?

                  II. Peaking of World Oil Production


                             A. Background

       Oil was formed by geological processes millions of years 
     ago and is typically found in underground reservoirs of 
     dramatically different sizes, at varying depths, and with 
     widely varying characteristics. The largest oil reservoirs 
     are called ``Super Giants,'' many of which were discovered in 
     the Middle East. Because of their size and other 
     characteristics, Super Giant reservoirs are generally the 
     easiest to find, the most economic to develop, and the 
     longest lived. The last Super Giant oil reservoirs discovered 
     worldwide were found in 1967 and 1968. Since then, smaller 
     reservoirs of varying sizes have been discovered in what are 
     called ``oil prone'' locations worldwide--oil is not found 
     everywhere.
       Geologists understand that oil is a finite resource in the 
     earth's crust, and at some future date, world oil production 
     will reach a maximum--a peak--after which production will 
     decline. This logic follows from the well-established fact 
     that the output of individual oil reservoirs rises after 
     discovery, reaches a peak and declines thereafter. Oil 
     reservoirs have lifetimes typically measured in decades, and 
     peak production often occurs roughly a decade or so after 
     discovery. It is important to recognize that oil production 
     peaking is not ``running out.'' Peaking is a reservoir's 
     maximum oil production rate, which typically occurs after 
     roughly half of the recoverable oil in a reservoir has been 
     produced. In many ways, what is likely to happen on a world 
     scale is similar to what happens to individual reservoirs, 
     because world production is the sum total of production from 
     many different reservoirs.
       Because oil is usually found thousands of feet below the 
     surface and because oil reservoirs normally do not have an 
     obvious surface signature, oil is very difficult to find. 
     Advancing technology has greatly improved the discovery 
     process and reduced exploration failures. Nevertheless, oil 
     exploration is still inexact and expensive.
       Once oil has been discovered via an exploratory well, full-
     scale production requires many more wells across the 
     reservoir to provide multiple paths that facilitate the flow 
     of oil to the surface. This multitude of wells also helps to 
     define the total recoverable oil in a reservoir--its so-
     called ``reserves.''


                            B. Oil Reserves

       The concept of reserves is generally not well understood. 
     ``Reserves'' is an estimate of the amount of oil in a 
     reservoir that can be extracted at an assumed cost. Thus, a 
     higher oil price outlook often means that more oil can be 
     produced, but geology places an upper limit on price-
     dependent reserves growth; in well managed oil fields, it is 
     often 10-20 percent more than what is available at lower 
     prices.
       Reserves estimates are revised periodically as a reservoir 
     is developed and new information provides a basis for 
     refinement. Reserves estimation is a matter of gauging how 
     much extractable oil resides in complex rock formations that 
     exist typically one to three miles below the surface of the 
     ground, using inherently limited information. Reserves 
     estimation is a bit like a blindfolded person trying to judge 
     what the whole elephant looks like from touching it in just a 
     few places. It is not like counting cars in a parking lot, 
     where all the cars are in full view.
       Specialists who estimate reserves use an array of 
     methodologies and a great deal of judgment. Thus, different 
     estimators might calculate different reserves from the same 
     data. Sometimes politics or self-interest influences reserves 
     estimates, e.g., an oil reservoir owner may want a higher 
     estimate in order to attract outside investment or to 
     influence other producers.
       Reserves and production should not be confused. Reserves 
     estimates are but one factor in estimating future oil 
     production from a given reservoir. Other factors include 
     production history, understanding of local geology, available 
     technology, oil prices, etc. An oil field can have large 
     estimated reserves, but if the field is past its maximum 
     production, the remaining reserves will be produced at a 
     declining rate. This concept is important because satisfying 
     increasing oil demand not only requires continuing to produce 
     older oil reservoirs with their declining production, it also 
     requires findinq new ones, capable of producing sufficient 
     quantities of oil to both compensate for shrinking production 
     from older fields and to

[[Page 26524]]

     provide the increases demanded by the market.


                         c. production peaking

       World oil demand is expected to grow 50 percent by 2025. To 
     meet that demand, ever-larger volumes of oil will have to be 
     produced. Since oil production from individual reservoirs 
     grows to a peak and then declines, new reservoirs must be 
     continually discovered and brought into production to 
     compensate for the depletion of older reservoirs. If large 
     quantities of new oil are not discovered and brought into 
     production somewhere in the world, then world oil production 
     will no longer satisfy demand. That point is called the 
     peaking of world conventional oil production.
       When world oil production peaks, there will still be large 
     reserves remaininq. Peaking means that the rate of world oil 
     production cannot increase: it also means that production 
     will thereafter decrease with time.
       The peaking of world oil production has been a matter of 
     speculation from the beginning of the modern oil era in the 
     mid 1800s. In the early days, little was known about 
     petroleum geology, so predictions of peaking were no more 
     than guesses without basis. Over time, geological 
     understanding improved dramatically and guessing gave way to 
     more informed projections, although the knowledge base 
     involves numerous uncertainties even today.
       Past predictions typically fixed peaking in the succeeding 
     10-20 year period. Most such predictions were wrong, which 
     does not negate that peaking will someday occur. Obviously, 
     we cannot know if recent forecasts are wrong until predicted 
     dates of peaking pass without incident.
       With a history of failed forecasts, why revisit the issue 
     now? The reasons are as follows:
       1. Extensive drilling for oil and gas has provided a 
     massive worldwide database; current geological knowledge is 
     much more extensive than in years past, i.e., we have the 
     knowledge to make much better estimates than previously.
       2. Seismic and other exploration technologies have advanced 
     dramatically in recent decades, greatly improving our ability 
     to discover new oil reservoirs. Nevertheless, the oil 
     reserves discovered per exploratory well began dropping 
     worldwide over a decade ago. We are finding less and less oil 
     in spite of vigorous efforts, suggesting that nature may not 
     have much more to provide.
       3. Many credible analysts have recently become much more 
     pessimistic about the possibility of finding the huge new 
     reserves needed to meet growing world demand.
       4. Even the most optimistic forecasts suggest that world 
     oil peaking will occur in less than 25 years.
       5. The peaking of world oil production could create 
     enormous economic disruption, as only glimpsed during the 
     1973 oil embargo and the 1979 Iranian oil cut-off.
       Accordingly, there are compelling reasons for in-depth, 
     unbiased reconsideration.


                            D. types of oil

       Oil is classified as ``Conventional'' and 
     ``Unconventional.'' Conventional oil is typically the highest 
     quality, lightest oil, which flows from underground 
     reservoirs with comparative ease. Unconventional oils are 
     heavy, often tar-like. They are not readily recovered since 
     production typically requires a great deal of capital 
     investment and supplemental energy in various forms. For that 
     reason, most current world oil production is conventional 
     oil. (Unconventional oil production will be discussed in 
     Chapter VI).


                            e. oil resources

       Consider the world resource of conventional oil. In the 
     past, higher prices led to increased estimates of 
     conventional oil reserves worldwide. However, this price-
     reserves relationship has its limits, because oil is found in 
     discrete packages (reservoirs) as opposed to the varying 
     concentrations characteristic of many minerals. Thus, at some 
     price, world reserves of recoverable conventional oil will 
     reach a maximum because of geological fundamentals. Beyond 
     that point, insufficient additional conventional oil will be 
     recoverable at any realistic price. This is a geological fact 
     that is often misunderstood by people accustomed to dealing 
     with hard minerals, whose geology is fundamentally different. 
     This misunderstanding often clouds rational discussion of oil 
     peaking.
       Future world recoverable reserves are the sum of the oil 
     remaining in existing reservoirs plus the reserves to be 
     added by future oil discoveries. Future oil production will 
     be the sum of production from older reservoirs in decline, 
     newer reservoirs from which production is increasing, and 
     yet-to-be discovered reservoirs.
       Because oil prices have been relatively high for the past 
     decade, oil companies have conducted extensive exploration 
     over that period, but their results have been disappointing. 
     If recent trends hold, there is little reason to expect that 
     exploration success will dramatically improve in the future. 
     This situation is evident in Figure 11-1, which shows the 
     difference between annual world oil reserves additions minus 
     annual consumption. The image is one of a world moving from a 
     long period in which reserves additions were much greater 
     than consumption, to an era in which annual additions are 
     falling increasingly short of annual consumption. This is but 
     one of a number of trends that suggest the world is fast 
     approaching the inevitable peaking of conventional world oil 
     production.


             f. impact of higher prices and new technology

       Conventional oil has been the mainstay of modern 
     civilization for more than a century, because it is most 
     easily brought to the surface from deep underground 
     reservoirs, and it is the most easily refined into finished 
     fuels. The U.S. was endowed with huge reserves of petroleum, 
     which underpinned U.S. economic growth in the early and mid 
     twentieth century. However, U.S. oil resources, like those in 
     the world, are finite, and growing U.S. demand resulted in 
     the peaking of U.S. oil production in the Lower 48 states in 
     the early 1970s. With relatively minor exceptions, U.S. Lower 
     48 oil production has been in continuing decline ever since. 
     Because U.S. demand for petroleum products continued to 
     increase, the U.S. became an oil importer. Today, the U.S. 
     depends on foreign sources for almost 60 percent of its 
     needs, and future U.S. imports are projected to rise to 70 
     percent of demand by 2025.
       Over the past 50 years, exploration for and production of 
     petroleum has been an increasingly more technological 
     enterprise, benefiting from more sophisticated engineering 
     capabilities, advanced geological understanding, improved 
     instrumentation, greatly expanded computing power, more 
     durable materials, etc. Today's technology allows oil 
     reservoirs to be more readily discovered and better 
     understood sooner than heretofore. Accordingly, reservoirs 
     can be produced more rapidly, which provides significant 
     economic advantages to the operators but also hastens peaking 
     and depletion.
       Some economists expect higher oil prices and improved 
     technologies to continue to provide ever-increasing oil 
     production for the foreseeable future. Most geologists 
     disagree because they do not believe that there are many huge 
     new oil reservoirs left to be found. Accordingly, geologists 
     and other observers believe that supply will eventually fall 
     short of growing world demand--and result in the peaking of 
     world conventional oil production.
       To gain some insight into the effects of higher oil prices 
     and improved technology on oil production, let us briefly 
     examine related impacts in the U.S. Lower 48 states. This 
     region is a useful surrogate for the world, because it was 
     one of the world's richest, most geologically varied, and 
     most productive up until 1970, when production peaked and 
     started into decline. While the U.S. is the best available 
     surrogate, it should be remembered that the decline rate in 
     U.S. production was in part impacted by the availability of 
     large volumes of relatively low cost oil from the Middle 
     East.
       The trend lines show a relatively symmetric, triangular 
     pattern. For reference, four notable petroleum market events 
     are noted in the figure: the 1973 OPEC oil embargo, the 1979 
     Iranian oil crisis, the 1986 oil price collapse, and the 1991 
     Iraq war.
       In constant dollars, oil prices increased by roughly a 
     factor of three in 1973-74 and another factor of two in 1979-
     80. The modest production up-ticks in the mid 1980s and early 
     1990s are likely responses to the 1973 and 1979 oil price 
     spikes, both of which spurred a major increase in U.S. 
     exploration and production investments. The delays in 
     production response are inherent to the implementation of 
     large-scale oil field investments. The fact that the 
     production up-ticks were moderate was due to the absence of 
     attractive exploration and production opportunities, because 
     of geological realities. Beyond oil price increases, the 
     1980s and 1990s were a golden age of oil field technology 
     development, including practical 3-D seismic, economic 
     horizontal drilling, and dramatically improved geological 
     understanding. Nevertheless, Lower 48 production still 
     trended downward, showing no pronounced response to either 
     price or technology. In light of this experience, there is 
     good reason to expect that an analogous situation will exist 
     worldwide after world oil production peaks: Higher prices and 
     improved technology are unlikely to yield dramatically higher 
     conventional oil production.


         g. projections of the peaking of world oil production

       Projections of future world oil production will be the sum 
     total of (1) output from all of the world's then existing 
     producing oil reservoirs, which will be in various stages of 
     development, and (2) all the yet-to-be discovered reservoirs 
     in their various states of development. This is an extremely 
     complex summation problem, because of the variability and 
     possible biases in publicly available data. In practice, 
     estimators use various approximations to predict future world 
     oil production. The remarkable complexity of the problem can 
     easily lead to incorrect conclusions, either positive or 
     negative.
       Various individuals and groups have used available 
     information and geological estimates to develop projections 
     for when world oil production might peak. A sampling of 
     recent projections is shown in Table II-1.

     TABLE II-1.--PROJECTIONS OF THE PEAKING OF WORLD OIL PRODUCTION
------------------------------------------------------------------------
                                       Source of        Background and
         Projected date               projection           reference
------------------------------------------------------------------------
2006-2007.......................  Bakhitari, A.M.S..  Iranian Oil
                                                       Executive

[[Page 26525]]

 
2007-2009.......................  Simmons, M.R......  Investment banker
After 2007......................  Skrebowski, C.....  Petroleum journal
                                                       Editor
Before 2009.....................  Deffeyes, K.S.....  Oil company
                                                       geologist (ret.)
Before 2010.....................  Goodstein, D......  Vice Provost, Cal
                                                       Tech
Around 2010.....................  Campbell, C.J.....  Oil company
                                                       geologist (ret.)
------------------------------------------------------------------------
After 2010......................  World Energy        World Non-
                                   Council.            Government Org.
2010-2020.......................  Laherrere, J......  Oil company
                                                       geologist (ret.)
2016............................  EIA nominal case..  DOE analysis/
                                                       information
------------------------------------------------------------------------
After 2020......................  CERA..............  Energy consultants
2025 or later...................  Shell.............  Major oil company
No visible peak.................  Lynch, M.C........  Energy economist
------------------------------------------------------------------------

           III. Why the Transition Will Be So Time Consuming


                            A. Introduction

       Use of petroleum is pervasive throughout the U.S. economy. 
     It is directly linked to all market sectors because all 
     depend on oil-consuming capital stock. Oil price shocks and 
     supply constraints can often be mitigated by temporary 
     decreases in consumption; however, long term price increases 
     resulting from oil peaking will cause more serious impacts. 
     Here we examine historical oil usage patterns by market 
     sector, provide a summary of current consumption patterns, 
     identify the most important markets, examine the relationship 
     between oil and capital stock, and provide estimates of the 
     time and costs required to transition to more energy 
     efficient technologies that can play a role in mitigating the 
     adverse effects of world oil peaking.


              B. Historical U.S. Oil Consumption Patterns

       After the two oil price shocks and supply disruptions in 
     1973-74 and 1979, oil consumption in the U.S. decreased 13 
     percent, declining from nearly 35 quads in 1973 to 30 quads 
     in 1983. However, overall consumption continued to grow after 
     the 1983 low and has continuously increased over the last 20 
     years, reaching over 39 quads in 2003, as shown in Figure 
     111-1. Of particular note are changes in three U.S. market 
     sectors: (1) Oil consumption in the residential sector 
     declined from eight percent of total oil consumption in 1973 
     to four percent in 2003, a decrease of 50 percent; (2) Oil 
     consumption in the commercial sector declined from five 
     percent to two percent, decreasing 58 percent; and (3) 
     Consumption in the electric power sector fell from 10 percent 
     in 1973 to three percent in 2003, decreasing 70 percent. 
     These three market sectors currently account for 1.3 quads of 
     oil consumption annually, representing nine percent of U.S. 
     oil demand in 2003.
       Oil consumption in other market sectors did not decrease. A 
     140 percent growth in GDP over the 1973-2003 period made it 
     difficult to decrease oil consumption in the industrial and 
     transportation sectors. In particular, personal 
     transportation grew significantly over the past three 
     decades, and total vehicle miles traveled for cars and light 
     trucks more than doubled over the period. From 1973 to 2003, 
     consumption of oil in the industrial sector stayed relatively 
     flat at just over nine quads, and the industrial sector's 
     share of total U.S. consumption remained between 24 and 26 
     percent. In sharp contrast to all other sectors, U.S. oil 
     consumption for transportation purposes has increased 
     steadily every year, rising from just over 17 quads in 1973 
     to 26 quads in 2003. By 2003, the transportation sector 
     accounted for two-thirds of the oil consumed in the U.S.


                C. Petroleum in the Current U.S. Economy

       The 39 quad consumption of oil in the U.S. in 2003 is 
     equivalent to 19.7 million barrels of oil per day (MM bpd), 
     including almost 13.1 MM bpd consumed by the transportation 
     sector and 4.9 MM bpd by the industrial sector, as shown in 
     Table III-1. This table also shows the petroleum fuel types 
     consumed by each sector. Motor gasoline consumption accounted 
     for 45 percent of U.S. daily petroleum consumption, nearly 9 
     MM bpd, almost all of which was used in autos and light 
     trucks. Distillate fuel oil was the second-most consumed oil 
     product at almost 3.8 MM bpd (19 percent of consumption), and 
     most was used as diesel fuel for medium and heavy trucks. 
     Finally, the third most consumed oil product was liquefied 
     petroleum gases, at 2.2 MM bpd equivalent (11 percent of 
     total consumption), most of which was used in the industrial 
     sector as feedstock by the chemicals industry. Only two other 
     consuming areas exceeded the 1 MM bpd level: kerosene and jet 
     fuel in the transportation sector, primarily for airplanes, 
     and ``other petroleum'' by the industrial sector, primarily 
     petroleum feedstocks used to produce non-fuel products in the 
     petroleum and chemical industries.

                                TABLE III-1.--DETAILED CONSUMPTION OF PETROLEUM IN THE U.S. BY FUEL TYPE AND SECTOR--2003
                                                              [Thousand of barrels per day]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Residential     Commercial      Industrial    Transportation  Electric Power       Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Motor Gasoline..........................................  ..............              20             159           8,665  ..............           8,844
Distillate Fuel Oil.....................................             421             236             603           2,455              51           3,766
LPG.....................................................             429              76           1,648              10  ..............           2,163
Kerosene/Jet Fuel.......................................              27               9               7           1,608  ..............           1,651
Residual................................................  ..............              30              87             250             291             658
Asphalt & Road Oil......................................  ..............  ..............             513  ..............  ..............             513
Petroleum Coke..........................................  ..............  ..............             398  ..............              61             459
Lubricants..............................................  ..............  ..............              78              73  ..............             151
Aviation Gas............................................  ..............  ..............  ..............              18  ..............              18
Other Petroleum.........................................  ..............  ..............           1,435  ..............  ..............           1,435
                                                         -----------------------------------------------------------------------------------------------
    Total...............................................             877             371           4,928          13,079             403          19,658
--------------------------------------------------------------------------------------------------------------------------------------------------------

   D. Capital Stock Characteristics in the Largest Consuming Sectors

       Energy efficiency improvements and technological changes 
     are typically incorporated into products and services slowly, 
     and their rate of market penetration is based on customer 
     preferences and costs. In the 1974-1983 period, oil prices 
     ratcheted up to newer, higher levels, which led to 
     significant energy efficiency improvements, energy fuel 
     switching, and other more general technological changes. Some 
     changes came about due to legislative mandates (corporate 
     average fuel economy standards, CAFE) or subsidies (solar 
     energy and energy efficiency tax credits), but many were the 
     result of economic decisions to reduce long-term costs. Under 
     a normal course of replacement based on historical trends, 
     oil-consuming capital stock has been replaced in the U.S. 
     over a period of 15 to 50 years and has cost consumers and 
     businesses trillions of dollars, as discussed below.
       Automobiles represent the largest single oil-consuming 
     capital stock in the U.S. 130 million autos consume 4.9 MM 
     bpd, or 25 percent of total consumption, as shown in Table 
     III-2. Autos remain in the U.S. transportation fleet, or 
     rolling stock, for a long time. While the financial-based 
     current-cost, average age of autos is only 3.4 years, the 
     average age of the stock is currently nine years.
       Recent studies show that one half of the 1990-model year 
     cars will remain on the road 17 years later in 2007. At 
     normal replacement rates, consumers will spend an estimated 
     $1.3 trillion (constant 2003 dollars) over the next 10-15 
     years just to replace one-half the stock of automobiles.

                TABLE III-2.--U.S. CAPITAL STOCK PROFILES
------------------------------------------------------------------------
                                           Light      Heavy       Air
                                Autos      Trucks     Trucks    Carriers
------------------------------------------------------------------------
Oil consumption (MM bpd)....        4.9        3.6        3.0        1.1
Share of the U.S. total.....        25%        18%        16%         6%
------------------------------------------------------------------------
Current cost of net capital      $571 B     $435 B     $686 B     $110 B
 stock (billion $)..........
------------------------------------------------------------------------
Fleet size..................     130 MM      80 MM       7 MM      8,500
Number of annual purchases..     8.5 MM     8.5 MM    500,000        400
Average age of stock (years)          9          7          9         13
Median lifetime (years).....         17         16         28         22
------------------------------------------------------------------------

       A similar situation exists with light trucks (vans, pick-
     ups, and SUVs), which consume 3.6 MM bpd of oil, accounting 
     for 18 percent of total oil consumption. Light trucks are 
     depreciated on a faster schedule, and their financial-based 
     current-cost average age is 2.9 years. However, the average 
     physical age of the rolling stock is seven years, and the 
     median lifetime of light trucks is 16 years. At current 
     replacement rates, one-half of the 80 million light trucks 
     will be replaced in the next 9-14 years at a cost of $1 
     trillion.
       Seven million heavy trucks (including buses, highway 
     trucks, and off-highway trucks) represent the third largest 
     consumer of oil at 3.0 MM bpd, 16 percent of total 
     consumption. The current-cost average age of heavy trucks is 
     5.0 years, but the median lifetime of this equipment is 28 
     years. The disparity in the average age and the median 
     lifetime estimates indicate that a significant number of 
     vehicles are 40-60 years old. At normal replacement levels, 
     one-half of the heavy truck stock will be replaced by 
     businesses in the next 15-20 years at a cost of $1.5 
     trillion.
       The fourth-largest consumer of oil is the airlines, which 
     consume the equivalent of 1.1 MM bpd, representing six 
     percent of U.S. consumption. The 8,500 aircraft have a 
     current-cost average age of 9.1 years, and a median lifetime 
     of 22 years. Airline deregulation and the events of September 
     11, 2001,

[[Page 26526]]

     have had significant effects on the industry, its ownership, 
     and recent business decisions. At recent rates, airlines will 
     replace one-half of their stock over the next 15-20 years at 
     a cost of $250 billion.
       These four capital stock categories cover most 
     transportation modes and represent 65 percent of the 
     consumption of oil in the U.S. The three largest categories 
     of autos, light trucks, and heavy trucks all utilize the 
     internal combustion engine, whether gasoline- or diesel-
     burning. Clearly, advancements in energy efficiency and 
     replacement in this capital stock (for instance, electric-
     hybrid engines) would help mitigate the economic impacts of 
     rising oil prices caused by world oil peaking. However, as 
     described, the normal replacement rates of this equipment 
     will require 10-20 years and cost trillions of dollars. We 
     cannot conceive of any affordable government-sponsored 
     ``crash proqram'' to accelerate normal replacement schedules 
     so as to incorporate higher energy efficiency technologies 
     into the privately-owned transportation sector; significant 
     improvements in energy efficiency will thus be inherently 
     time-consuming (of the order of a decade or more).
       When oil prices increase associated with oil peaking, 
     consumers and businesses will attempt to reduce their 
     exposure by substitution or by decreases in consumption. In 
     the short run, there may be interest in the substitution of 
     natural gas for oil in some applications, but the current 
     outlook for natural gas availability and price is cloudy for 
     a decade or more. An increase in demand for electricity in 
     rail transportation would increase the need for more electric 
     power plants. In the short run, much of the burden of 
     adjustment will likely be borne by decreases in consumption 
     from discretionary decisions, since 67 percent of personal 
     automobile travel and nearly 50 percent of airplane travel 
     are discretionary.


                    E. Consumption Outside the U.S.

       Oil consumption patterns differ in other countries. While 
     two-thirds of U.S. oil use is in the transportation sector, 
     worldwide that share is estimated about 55 percent. However, 
     that difference is narrowing as world economic development is 
     expanding transportation demands at an even faster pace. A 
     portion of nontransportation oil consumption is switchable. 
     As stated by EIA, ``Oil's importance in other end-use sectors 
     is likely to decline where other fuels are competitive, such 
     as natural gas, coal, and nuclear, in the electric sector, 
     but currently there are no alternative energy sources that 
     compete economically with oil in the transportation sector.'' 
     Because sector-by-sector oil consumption data for many 
     counties is unavailable, a detailed analysis of world 
     consumption was beyond the scope of this report. 
     Nevertheless, it is clear that transportation is the primary 
     market for oil worldwide.


                       F. Transition Conclusions

       Any transition of liquid fueled, end-use equipment 
     following oil peaking will be time consuming. The depreciated 
     value of existing U.S. transportation capital stock is nearly 
     $2 trillion and would normally require 25-30 years to 
     replace. At that rate, significantly more energy efficient 
     equipment will only be slowly phased into the marketplace as 
     new capital stock gradually replaces existing stock. Oil 
     peaking will likely accelerate replacement rates, but the 
     transition will still require decades and cost trillions of 
     dollars.

   IV. Lessons and Implications From Previous Oil Supply Disruptions


            A. Previous Oil Supply Shortfall and Disruptions

       There have been over a dozen global oil supply disruptions 
     over the past half-century.
       Briefly, disruptions ranged in duration from one to 44 
     months. Supply shortfalls were 0.3-4.6 MM bpd, and eight 
     resulted in average gross supply shortfalls of at least 2 MM 
     bpd. Percentage supply shortfalls varied from roughly one 
     percent to nearly 14 percent of world production. The most 
     traumatic disruption, 1973-74, was not the most severe, but 
     it nevertheless lead to greatly increased oil prices and 
     significant worldwide economic damage. The second most 
     traumatic disruption, 1979, was also neither the longest nor 
     the most severe.
       For purposes of this study, the 1973-74 and 1979 
     disruptions are taken as the most relevant, because they are 
     believed to offer the best insights into what miqht occur 
     when world oil production peaks.


     B. Difficulties in Deriving Implications From Past Experience

       Over the past 30 years, most economic studies of the impact 
     of oil supply disruptions assumed that the interruptions were 
     temporary and that each situation would shortly return to 
     ``normal'' Thus, the major focus of most studies was 
     determination of the appropriate fiscal and monetary policies 
     required to minimize negative economic impacts and the 
     development of policies to help the economy and labor market 
     adjust until the disruption ended. Few economists considered 
     a situation where the oil supply shortfall may be long-lived 
     (a decade or more).
       Since 1970, most large oil price increases were eventually 
     followed by oil price declines, and, since these cycles were 
     expected to be repeated, it was generally felt that ``the 
     problem will take care of itself as long at the government 
     does nothing and does not interfere. The frequent and 
     incorrect predictions of oil shortfalls have been often used 
     to discredit future predictions of a longer-term problem and 
     to discredit the need for appropriate long-term U.S. energy 
     policies.


         c. How Oil Supply Shortfalls Affect the Global Economy

       Oil prices playa key role in the global economy, since the 
     major impact of an oil supply disruption is higher oil 
     prices. Oil price increases transfer income from oil 
     importing to oil exporting countries, and the net impact on 
     world economic growth is negative. For oil importing 
     countries, increased oil prices reduce national income 
     because spending on oil rises, and there is less available to 
     spend on other goods and services. Not surprisingly, the 
     larger the oil price increase and the longer higher prices 
     are sustained, the more severe is the macroeconomic impact.
       Higher oil prices result in increased costs for the 
     production of goods and services, as well as inflation, 
     unemployment, reduced demand for products other than oil, and 
     lower capital investment. Tax revenues decline and budget 
     deficits increase, driving up interest rates. These effects 
     will be greater the more abrupt and severe the oil price 
     increase and will be exacerbated by the impact on consumer 
     and business confidence.
       Government policies cannot eliminate the adverse impacts of 
     sudden, severe oil disruptions, but they can minimize them. 
     On the other hand, contradictory monetary and fiscal policies 
     to control inflation can exacerbate recessionary income and 
     unemployment effects. (See Appendix II for further discussion 
     of past government actions).


                         D. The U.S. Experience

       Oil price increases have preceded most U.S. recessions 
     since 1969, and virtually every serious oil price shock was 
     followed by a recession. Thus, while oil price spikes may not 
     be necessary to trigger a recession in the U.S., they have 
     proven to be sufficient over the past 30 years.


                  E. The Experience of Other Countries

     1. The developed (OECD) economies
       Estimates of the damage caused by past oil price 
     disruptions vary substantially, but without a doubt, the 
     effects were significant. Economic growth decreased in most 
     oil importing countries following the disruptions of 1973-74 
     and 1979-80, and the impact of the first oil shock was 
     accentuated by inappropriate policy responses. Despite a 
     decline in the ratio of oil consumption to GDP over the past 
     three decades, oil remains vital, and there is considerable 
     empirical evidence regarding the effects of oil price shocks:
       The loss suffered by the OECD countries in the 1974-75 
     recession amounted to $350 billion (current dollars) / $1.1 
     trillion 2003 dollars, althouh part of this loss was related 
     to factors other than oil price. The loss resulting from the 
     1979 oil disruption was about three percent of GDP ($350 
     billion in current dollars) in 1980 rising to 4.25 percent 
     ($570 billion) in 1981, and accounted for much of the decline 
     in economic growth and the increase in inflation and 
     unemployment in the OECD in 1981-82. The effect of the 1990-
     91 oil price upsurge was more modest, because price increases 
     were smaller; they did not persist; and oil intensity in OECD 
     countries had declined. Although oil intensity and the share 
     of oil in total imports have declined in recent years, OECD 
     economies remain vulnerable to higher oil prices, because of 
     the ``life blood'' nature of liquid fuel use.
     2. Developing countries
       Developing countries suffer more than the developed 
     countries from oil price increases because they generally use 
     energy less efficiently and because energy-intensive 
     manufacturing accounts for a larger share of their GDP. On 
     average, developing countries use more than twice as much oil 
     to produce a unit of output as developed countries, and oil 
     intensity is increasing in developing countries as commercial 
     fuels replace traditional fuels and industrialization/
     urbanization continues.
       The vulnerability of developing countries is exacerbated by 
     their limited ability to switch to alternative fuels. In 
     addition, an increase in oil import costs also can 
     destabilize trade balances and increase inflation more in 
     developing countries, where financial institutions and 
     monetary authorities are often relatively unsophisticated. 
     This problem is most pronounced for the poorest developing 
     countries.


                            F. Implications

     1. The world economy
       A shortfall of oil supplies caused by world conventional 
     oil production peaking will sharply increase oil prices and 
     oil price volatility. As oil peaking is approached, 
     relatively minor events will likely have more pronounced 
     impacts on oil prices and futures markets.
       Oil prices remain a key determinant of global economic 
     performance, and world economic growth over the past 50 years 
     has been negatively impacted in the wake of increased oil 
     prices. The greater the supply shortfall,

[[Page 26527]]

     the higher the price increases; the longer the shortfall, the 
     greater will be the adverse economic affects.
       The long-run impact of sustained, significantly increased 
     oil prices associated with oil peaking will be severe. 
     Virtually certain are increases in inflation and 
     unemployment, declines in the output of goods and services, 
     and a degradation of living standards. Without timely 
     mitigation, the long-run impact on the developed economies 
     will almost certainly be extremely damaging, while many 
     developing nationsly be even worse off.
       The impact of oil price changes will likely be asymmetric. 
     The negative economic effects of oil price increases are 
     usually not offset by the economic stimulus resulting from a 
     fall in oil prices. The increase in economic growth in oil 
     exporting countries provided by higher oil prices has been 
     less than the loss of economic growth in importing countries, 
     and these effects will likely continue in the future.
     2. The United States
       For the U.S., each 50 percent sustained increase in the 
     price of oil will lower real U.S. GDP by about 0.5 percent, 
     and a doubling of oil prices would reduce GDP by a full 
     percentage point. Depending on the U.S. economic growth rate 
     at the time, this could be a sufficient negative impact to 
     drive the country into recession. Thus, assuming an oil price 
     in the $25 per barrel range--the 2002-2003 average, an 
     increase of the price of oil to $50 per barrel would cost the 
     economy a reduction in GDP of around $125 billion.
       If the shortfall persisted or worsened (as is likely in the 
     case of peaking), the economic impacts would be much greater. 
     Oil supply disruptions over the past three decades have cost 
     the U.S. economy about $4 trillion, so supply shortfalls 
     associated with the approach of peaking could cost the U.S. 
     as much as all of the oil supply disruptions since the early 
     1970s combined.
       The effects of oil shortages on the U.S. are also likely to 
     be asymmetric. Oil supply disruptions and oil price increases 
     reduce economic activity, but oil price declines have a less 
     beneficial impact. Oil shortfalls and price increases will 
     cause larger responses in job destruction than job creation, 
     and many more jobs may be lost in response to oil price 
     increases than will be regained if oil prices were to 
     decrease. These effects will be more pronounced when oil 
     price volatility increases as peaking is approached. The 
     repeated economic and job losses experienced during price 
     spikes will not be replaced as prices decrease. As these 
     cycles continue, the net economic and job losses will 
     increase.
       Sectoral shifts will likely be pronounced. Even moderate 
     oil disruptions could cause shifts among sectors and 
     industries of ten percent or more of the labor force. 
     Continuing oil shortages will likely have disruptive inter-
     industry, and inter-regional effects, and the sectors that 
     are (both directly and indirectly) oil-dependent could be 
     severely impacted.
       Monetary policy is more effective in controlling the 
     inflationary effects of a supply disruption than in averting 
     related recessionary effects. Thus, while appropriate 
     monetary policy may be successful in lessening the 
     inflationary impacts of oil price increases, it may do so at 
     the cost of recession and increased unemployment. Monetary 
     policies tend to be used to increase interest rates to 
     control inflation, and it is the high interest rates that 
     cause most of the economic damage. As peaking is approached, 
     devising appropriate offsetting fiscal, monetary, and energy 
     policies will become more difficult. Economically, the decade 
     following peaking may resemble the 1970s, only worse, with 
     dramatic increases in inflation, long-term recession, high 
     unemployment, and declining living standards.

              V. Learning From the Natural Gas Experience


                            A. Introduction

       A dramatic example of the risks of over-reliance on 
     geological resource projections is the experience with North 
     American natural gas. Natural gas supplies roughly 20 percent 
     of U.S. energy demand. It has been plentiful at real prices 
     of roughly $2/Mcf for almost two decades. Over the past 10 
     years, natural gas has become the fuel of choice for new 
     electric power generation plants and, at present, virtually 
     all new electric power generation plants use natural gas.
       Part of the attractiveness of natural gas was resource 
     estimates for the U.S. and Canada that promised growing 
     supply at reasonable prices for the foreseeable future. That 
     optimism turns out to have been misplaced, and the U.S. is 
     now experiencing supply constraints and high natural gas 
     prices. Supply difficulties are almost certain for at least 
     the remainder of the decade. The North American natural gas 
     situation provides some useful lessons relevant to the 
     peaking of conventional world oil production.


                            B. The Optimism

       As recently as 2001, a number of credible groups were 
     optimistic about the ready availability of natural gas in 
     North America. For example:
       In 1999 the National Petroleum Council stated ``U.S. 
     production is projected to increase from 19 trillion cubic 
     feet (Tcf) in 1998 to 25 Tcf in 2010 and could approach 27 
     Tcf in 2015 . . . Imports from Canada are projected to 
     increase from 3 Tcf in 1998 to almost 4 Tcf in 2010.''
       In 2001 Cambridge Energy Research Associates (CERA) stated 
     ``The rebound in North American gas supply has begun and is 
     expected to be maintained at least through 2005. In total, we 
     expect a combination of US lower-48 activity, growth in 
     Canadian supply, and growth in LNG imports to add 8.95 Bcf 
     per day of production by 2005.''
       The U.S. Energy Department's Energy Information 
     Administration (EIA) in 1999 projected that U.S. natural gas 
     production would grow continuously from a level of 19.4 Tcf 
     in 1998 to 27.1 Tcf in 2020.


                        C. Today's Perspectives

       The current natural gas supply outlook has changed 
     dramatically. Among those that believe the situation has 
     changed for the worse are the following:
       CERA now finds that ``The North American natural gas market 
     is set for the longest period of sustained high prices in its 
     history, even adjusting for inflation. Disappointing drilling 
     results . . . have caused CERA to revise the outlook for 
     North American supply downward . . . The downward revisions 
     represent additional disappointing supply news, painting a 
     more constrained picture for continental supply. Gas 
     production in the United States (excluding Alaska) now 
     appears to be in permanent decline, and modest gains in 
     Canadian supply will not overcome the U.S. downturn.
       Raymond James & Associates finds that ``Natural gas 
     production continues to drop despite a 20 percent increase in 
     U.S. drilling activity since April 2003. ``U.S. natural gas 
     production is heading firmly down-
     wards . . .''
       ``Lehman now expects full-year U.S. production to decline 
     by 4% following a 6% decline in 2003. . . . Domestic 
     production is forecast to fall to 41.0 billion cubic feet a 
     day by 2008 from 46.8 in 2003 and 52.1 in 1998. After a sharp 
     12% fall in 2003, Canadian imports are seen dropping.''
       The NPC now contends that ``Current higher gas prices are 
     the result of a fundamental shift in the supply and demand 
     balance. North America is moving to a period in its history 
     in which it will no longer be self-reliant in meeting its 
     growing natural gas needs; production from traditional U.S. 
     and Canadian basins has plateaued.''
       Canada has been a reliable U.S. source of natural gas 
     imports for decades. However, the Canadian situation has 
     recently changed for the worse. For example: ``Natural gas 
     production in Alberta, the largest exporter to the huge U.S. 
     market, slipped 2 percent last year despite record drilling 
     and may have peaked in 2001, the Canadian province's energy 
     regulator said on Thursday . . . Production peaked at 5.1 
     trillion cubic feet in 2001. . . . (EUB) forecast flat 
     production in 2004 and an annual decline of 2.5 percent 
     through at least 2013.''


                   D. U.S. Natural Gas Price History

       EIA data show that U.S. natural gas prices were relatively 
     stable in constant dollars from 1987 through 1998. However, 
     beginning in 2000, prices began to escalate--they were 
     roughly 50 percent higher in 2000 compared to 1998. Skipping 
     over the recession years of 2001 and 2002, prices in late 
     2003 and early 2004 further increased roughly 25 percent over 
     2000.
       While it is often inappropriate to extrapolate gas or oil 
     prices into the future based on short term experience, a 
     number of organizations are now projecting increased U.S. 
     natural gas prices for a number of years. For example, CERA 
     now expects natural gas prices to rise steadily through 2007.


                       E. LNG--Delayed Salvation

       With North American natural gas production suddenly 
     changed, hopes of meeting future demand have turned to 
     imports of liquefied natural gas (LNG). The U.S. has four 
     operating LNG terminals, and a number of proposals for new 
     terminals have been advanced. Indeed, the Secretary of Energy 
     and the Chairman of the Federal Reserve Board recently called 
     for a massive buildup in LNG imports to meet growing U.S. 
     natural gas demand.
       But the construction of new terminals demands state and 
     local approvals. Because of NIMBYism and fear of terrorism at 
     LNG facilities, a number of the proposed terminals have been 
     rejected. There are also objections from Mexico, which has 
     been proposed as a host for LNG terminals to support west 
     coast natural gas demands. In the Boston area there is an 
     ongoing debate as to whether the nation's largest LNG 
     terminal in Everett, Massachusetts, ought to be shut down, 
     because of terrorist concerns. Decommissioning of that 
     terminal would exacerbate an already tight national natural 
     gas supply situation. Public fears about LNG safety were 
     heightened by an explosion at an LNG liquefaction plant in 
     Algeria that killed 27 people in January 2004. Alternatively, 
     some are considering locating LNG terminals offshore with gas 
     pipelined underwater to land; related costs will be higher, 
     but safety would be enhanced.


               F. The U.S. Current Natural Gas Situation

       U.S. natural gas demand is increasing; North American 
     natural gas production is declining or poised for decline as 
     indicated in references 53, 54, and 55. The planned U.S. 
     expansion of LNG imports is experiencing

[[Page 26528]]

     delays. U.S. natural gas supply shows every sign of 
     deteriorating significantly before mitigation provides an 
     adequate supply of low cost natural gas. Because of the time 
     required to make major changes in the U.S. natural gas 
     infrastructure and marketplace, forecasts of a decade of high 
     prices and shortages are credible.


                           G. Lessons Learned

       A full discussion of the complex dimensions of the current 
     U.S. natural gas situation is beyond the scope of this study; 
     such an effort would require careful consideration of 
     geology, reserves estimation, natural gas exploration and 
     production, government land restrictions, storage, weather, 
     futures markets, etc. Nevertheless, we believe that the 
     foregoing provides a basis for the following observations: 
     Like oil reserves estimation, natural gas reserves estimation 
     is subject to enormous uncertainty. North American natural 
     gas reserves estimates now appear to have been excessively 
     optimistic and North American natural gas production is now 
     almost certainly in decline. High prices do not a priori lead 
     to greater production. Geology is ultimately the limiting 
     factor, and geological realities are clearest after the fact. 
     Even when urgent, nation-scale energy problems arise, 
     business-as-usual mitigation activities can be dramatically 
     delayed or stopped by state and local opposition and other 
     factors.
       If experts were so wrong on their assessment of North 
     American natural gas, are we really comfortable risking that 
     the optimists are correct on world conventional oil 
     production, which involves similar geological and 
     technological issues?
       If higher prices did not bring forth vast new supplies of 
     North American natural gas, are we really comfortable that 
     higher oil prices will bring forth huge new oil reserves and 
     production, when similar geology and technologies are 
     involved?

                   VI. Mitigation Options and Issues


                            A. Conservation

       Practical mitigation of the problems associated with world 
     oil peaking must include fuel efficiency technologies that 
     could impact on a large scale. Technologies that may offer 
     significant fuel efficiency improvements fall into two 
     categories: retrofits, which could improve the efficiency of 
     existing equipment, and displacement technologies, which 
     could replace existing, less efficient oil consuming 
     equipment. A comprehensive discussion of this subject is 
     beyond the scope of this study, so we focus on what we 
     believe to be the highest impact, existing technologies. 
     Clearly, other technologies might contribute on a lesser 
     scale.
       From our prior discussion of current liquid fuel usage 
     (Chapter III), it is clear that automobiles and light trucks 
     (light duty vehicles or LDVs) represent the largest targets 
     for consumption reduction. This should not be surprising: 
     Auto and LDV fuel use is large, and fuel efficiency has not 
     been a consumer priority for decades, largely due to the 
     historically low cost of gasoline. An established but 
     relatively little-used engine technology for LDVs in the U.S. 
     is the diesel engine, which is up to 30 percent more 
     efficient than comparable gasoline engines. Future U.S. use 
     of diesels in LDVs has been problematic due to increasingly 
     more stringent U.S. air emission requirements. European 
     regulations are not as restrictive, so Europe has a high 
     population of diesel LDVs--between 55 and 70 percent in some 
     countries.
       A new technology in early commercial deployment is the 
     hybrid system, based on either gasoline or diesel engines and 
     batteries. In all-around driving tests, gasoline hybrids have 
     been found to be 40 percent more efficient in small cars and 
     80 percent more efficient in family sedans.
       For retrofit application, neither diesel nor hybrid engines 
     appear to have significant potential, so their use will 
     likely be limited to new vehicles. Under business-as-usual 
     market conditions, hybrids might reach roughly 10 percent on-
     the-road U.S. market share by 2015. That penetration rate is 
     based on the fact that the technology has met many of the 
     performance demands of a significant number of today's 
     consumers and that gasoline hybrids use readily available 
     fuel.
       Government-mandated vehicle fuel efficiency requirements 
     are virtually certain to be an element in the mitigation of 
     world oil peaking. One result would almost certainly be the 
     more rapid deployment of diesel and/or hybrid engines. Market 
     penetration of these technologies cannot happen rapidly, 
     because of the time and effort required for manufacturers to 
     retool their factories for large-scale production and because 
     of the slow turnover of existing stock. In addition, a shift 
     from gasoline to diesel fuel would require a major refitting 
     of refineries, which would take time.
       Nation-scale retrofit of existing LDVs to provide improved 
     fuel economy has not received much attention. One retrofit 
     technology that might prove attractive for the existing LDV 
     fleet is ``displacement on demand'' in which a number of 
     cylinders in an engine are disabled when energy demand is 
     low. The technology is now available on new cars, and fuel 
     economy savings of roughly 20 percent have been claimed. The 
     feasibility and cost of such retrofits are not known, so we 
     consider this option to be speculative.
       It is difficult to project what the fuel economy benefits 
     of hybrid or diesel LDVs might be on a national scale, 
     because consumer preferences will likely change once the 
     public understands the potential impacts of the peaking of 
     world oil production. For example, the current emphasis on 
     large vehicles and SUVs might well give way to preferences 
     for smaller, much more fuel-efficient vehicles.
       The fuel efficiency benefits that hybrids might provide for 
     heavy-duty trucks and buses are likely smaller than for LDVs 
     for a number of reasons, including the fact that there has 
     long been a commercial demand for higher efficiency 
     technologies in order to minimize fuel costs for these 
     fleets.
       Hybrids can also impact the medium duty truck fleet, which 
     is now heavily populated with diesel engines. For example, 
     road testing of diesel hybrids in FedEx trucks recently 
     began, with fuel economy benefits of 33 percent claimed. On 
     the other hand, there appears to be limits to the fuel 
     economy benefits of hybrid engines in large vehicles; for 
     example, the fuel savings in hybrid buses might only be in 
     the 10 percent range.
       On the distant horizon, innovations in aircraft design may 
     result in large fuel economy improvements. For example, a 25 
     to 50 percent fuel efficiency improvement may be possible 
     with a new, blended wing aircraft. Such benefits would 
     require the purchase of entirely new equipment, requiring a 
     decade or more for significant market penetration. 
     Innovations for major liquid fuel savings for trains and 
     ships may exist but are not widely publicized.


                        B. Improved Oil Recovery

       Management of an oil reservoir over its multi-decade life 
     is influenced by a range of factors, including (1) actual and 
     expected future oil prices; (2) production history, geology, 
     and status of the reservoir; (3) cost and character of 
     production-enhancing technologies; (4) timing of 
     enhancements; (5) the financial condition of the operator; 
     (6) political and environmental circumstances; (7) an 
     operator's other investment opportunities, etc.
       Improved Oil Recovery (IOR) is used to varying degrees on 
     all oil reservoirs. IOR encompasses a variety of methods to 
     increase oil production and to expand the volume of 
     recoverable oil from reservoirs. Options include in-fill 
     drilling, hydraulic fracturing, horizontal drilling, advanced 
     reservoir characterization, enhanced oil recovery (EOR), and 
     a myriad of other methods that can increase the flow and 
     recovery of liquid hydrocarbons. IOR can also include many 
     seemingly mundane efficiencies introduced in daily 
     operations.
       IOR technologies are adapted on a case-by-case basis. It is 
     not possible to estimate what IOR techniques or processes 
     might be applied to a specific reservoir without having 
     detailed knowledge of that reservoir. Such knowledge is 
     rarely in the public domain for the large conventional oil 
     reservoirs in the world; if it were, then a more accurate 
     estimate of the timing of world oil peaking would be 
     possible.
       A particularly notable opportunity to increase production 
     from existing oil reservoirs is the use of enhanced oil 
     recovery technology (EOR), also known as tertiary recovery. 
     EOR is usually initiated after primary and secondary recovery 
     have provided most of what they can provide. Primary 
     production is the process by which oil naturally flows to the 
     surface because oil is under pressure underground. Secondary 
     recovery involves the injection of water into a reservoir to 
     force additional oil to the surface.
       EOR has been practiced since the 1950s in various 
     conventional oil reservoirs, particularly in the United 
     States. The process that likely has the largest worldwide 
     potential is miscible flooding wherein carbon dioxide 
     (CO2), nitrogen or light hydrocarbons are injected 
     into oil reservoirs where they act as solvents to move 
     residual oil. Of the three options, CO2 flooding 
     has proven to be the most frequently useful. Indeed, 
     naturally occurring, geologically sourced CO2 has 
     been produced in Colorado and shipped via pipeline to west 
     Texas and New Mexico for decades for EOR. CO2 
     flooding can increase oil recovery by 7-15 percent of 
     original oil in place (OOIP). Because EOR is relatively 
     expensive, it has not been widely deployed in the past. 
     However, in a world dealing with peak conventional oil 
     production and higher oil prices, it has significant 
     potential.
       Because of various cost considerations, enhanced oil 
     recovery processes are typically not applied to a 
     conventional oil reservoir until after oil production has 
     peaked. Therefore, EOR is not likely to increase reservoir 
     peak production. However, EOR can increase total recoverable 
     conventional oil, and production from the reservoirs to which 
     it is applied does not decline as rapidly as would otherwise 
     be the case.


                       c. Heavy Oil and Oil Sands

       This category of unconventional oil includes a variety of 
     viscous oils that are called heavy oil, bitumen, oil sands, 
     and tar sands. These oils have potential to play a much 
     larger role in satisfying the world's needs for liquid fuels 
     in the future.
       The largest deposits of these oils exist in Canada and 
     Venezuela, with smaller resources in Russia, Europe and the 
     U.S. While the size of the Canadian and Venezuela resources 
     are enormous, 3-4 trillion barrels in

[[Page 26529]]

     total, the amount of oil estimated to be economically 
     recoverable is of the order of 600 billion barrels. This 
     relatively low fraction is in large part due to the extremely 
     difficult task of extracting these oils.
       Canadian oil sands production results in a range of 
     products, only a part of which can be refined into finished 
     fuels that can substitute for petroleum-based fuels. These 
     high quality oil-sands-derived products are called synthetic 
     crude oil (SCO). Other products from oil sands processing are 
     Dilbit, a blend of diluent and bitumen, Synbit, a blend of 
     synthetic crude oil and bitumen, and Syndilbit, a blend of 
     Synbit and diluent. Current Canadian production is 
     approximately 1 million bpd of which 600,000 bpd is synthetic 
     crude oil and 400,000 bpd is lower grade bitumen.
       The reasons why the production of unconventional oils has 
     not been more extensive is as follows: (1) Production costs 
     for unconventional oils are typically much higher than for 
     conventional oil; (2) Significant quantities of energy are 
     required to recover and transport unconventional oils; and 
     (3) Unconventional oils are of lower quality and, therefore, 
     are more expensive to refine into clean transportation fuels 
     than conventional oils.
       Canadian oil sands have been in commercial production for 
     decades. During that time, production costs have been reduced 
     considerably, but costs are still substantially higher than 
     conventional oil production. Canadian oil sands production 
     currently uses large amounts of natural gas for heating and 
     processing. Canada recently recognized that it no longer has 
     the large natural gas resources once thought, so oil sands 
     producers are considering building coal or nuclear plants as 
     substitute energy sources to replace natural gas. The overall 
     efficiency of Canadian oil sands production is not publicly 
     available but has been estimated to be less than 70 percent 
     for total product, only a part of which is a high-quality 
     substitute transport fuel.
       In addition to needing a substitute for natural gas for 
     processing oil sands, there are a number of other major 
     challenges facing the expansion of Canadian oil sands 
     production, including water and diluent availability, 
     financial capital, and environmental issues, such as 
     SOX and NOX emissions, waste water 
     cleanup, and brine, coke, and sulfur disposition. In 
     addition, because Canada is a signatory to the Kyoto Protocol 
     and because oil sands production results in significant 
     CO2 emissions per barrel, there may be related 
     constraints yet to be fully evaluated.
       The current Canadian vision is to produce a total of about 
     5 MM bpd of products from oil sands by 2030. This is to 
     include about 3 MM bpd of synthetic crude oil from which 
     refined fuels can be produced, with the remainder being 
     poorer quality bitumen that could be used for energy, power, 
     and/or hydrogen and petrochemicals production. 5 MM bpd would 
     represent a five-fold increase from current levels of 
     production. Another estimate of future production states that 
     if all proposed oil sands projects proceed on schedule, 
     industry could produce 3.5 MM bpd by 2017, representing 2 MM 
     bpd of synthetic crude and 1.5 MM bpd of unprocessed lower-
     grade bitumen. It should be noted that not everyone supports 
     this expansion. For example, the executive director of the 
     Sierra Club of Canada, calls tar sands''. . . the world's 
     dirtiest source of oil.
       Venezuela's extra-heavy crude oil and bitumen deposits are 
     situated in the Orinoco Belt, located in Central Venezuela. 
     There are currently a number of joint ventures between the 
     Venezuelan oil company, PdVSA, and foreign partners to 
     develop and produce this oil. In 2003, production was about 
     500,000 bpd of synthetic crude oil. That is expected to 
     increase to 600,000 bpd by 2005. While the weather in 
     tropical Venezuela is more conducive to oil production 
     operations than the bitter winters of Alberta, Canada, the 
     political climate in Venezuela has been particularly 
     unsettled in recent years, which could impact future 
     production.
       In closing, it is also worth noting that the bitumen yield 
     from oil sands surface mining operations is about 0.6 barrels 
     per ton of mined material, excluding overburden removal. This 
     is similar to the yield from a good quality oil shale, but is 
     less than Fisher-Tropsch liquid yields from coal, which is 
     about 2.6 barrels per ton of coal.


                        D. Gas-To-Liquids (GTL)

       Very large reservoirs of natural gas exist around the 
     world, many in locations isolated from gas-consuming markets. 
     Significant quantities of this ``stranded gas'' have been 
     liquefied and transported to various markets in refrigerated, 
     pressurized ships in the form of liquefied natural gas (LNG). 
     Japan, followed by Korea, Spain and the U.S. were the largest 
     importers of LNG in 2003. LNG accounted for an important 
     fraction of all traded gas volumes in 2003, and that fraction 
     is projected to continue to grow considerably in the future.
       Another method of bringing stranded natural gas to world 
     markets is to disassociate the methane molecules, add steam, 
     and convert the resultant mixture to high quality liquid 
     fuels via the Fisher-Tropsch (F-T) process. As with coal 
     liquefaction, F-T based GTL results in clean, finished fuels, 
     ready for use in existing end-use equipment with only modest 
     finishing and blending. This Gas-To-Liquids process has 
     undergone significant development over the past decade. Shell 
     now operates a 14,500 bpd GTL plant in Malaysia. A number of 
     large, new commercial plants recently announced include three 
     large units in Qatar--a 140,000 bpd Shell facility, a 160,000 
     bpd ConocoPhillips facility, and a 120,000 bpd Marathon Oil 
     plant. Projects under development and consideration total 
     roughly 1.7 MM bpd, but not all will come to fruition. Under 
     business-as-usual conditions, 1.0 MM bpd may be produced by 
     2015, in line with a recent estimate of 600,000 bpd of GTL 
     diesel fuel by 2015--the remaining 400,000 bpd being gasolin 
     and other products.


              E. Liquid Fuels from U.S. Domestic Resources

       The U.S. has three types of natural resource from which 
     substitute liquid fuels can be manufactured: coal, oil shale, 
     and biomass. All have been shown capable of producing high 
     quality liquid fuels that can supplement or substitute for 
     the fuels ow produced from petroleum.
       To derive liquid fuels from coal, the leading process 
     involves gasification of the coal, removal of impurities from 
     the resultant gas, and then synthesis of liquid fuels using 
     t1e Fisher-Tropsch process. Modern gasification technologies 
     have been dramatically improved over the years, with the 
     result that over 150 gasifiers are in commercial operation 
     around the world, a number operating on coal. Gas cleanup 
     technologies are well developed and utilized in refineries 
     worldwide. F-T synthesis is also well developed and 
     commercially practiced. A number of coal liquefaction plants 
     were built and operated during World War II, and the Sasol 
     Company in South Africa subsequently built a number of 
     larger, more modern facilities. The U.S. has huge coal 
     reserves that are now being utilized for the production of 
     electricity; those resources could also provide feedstock for 
     large-scale liquid fuel production. Lastly, coal liquids from 
     gasification/F-T synthesis are of such high quality that they 
     do not need to be refined. When co-producing electricity, 
     coal liquefaction is a developed technology, currently 
     believed capable of providing clean substitute fuels at $30-
     35 per barrel.
       The U.S. is endowed with a vast resource of oil shale, 
     located primarily in the western part of the Lower 48 states 
     with lesser quantities in the mid Atlantic region. Processes 
     for mining shale and retorting it at high temperatures were 
     developed in intensively in the late 1970s and early 1980s. 
     However, when oil prices decreased in the mid 1980s, all 
     large-scale oil shale R&D was terminated.
       The oil shale processing technologies that were pursued in 
     the past required large volumes of water, which is now 
     increasingly scarce in the western states. Also, air 
     emissions regulations have become much stricter in the 
     ensuing years, presenting additional challenges for shale 
     mining and processing. Finally, it should be noted that the 
     oil produced from shale retorting requires refining before it 
     can be used as transportation fuels.
       In recent years, Shell has been developing a new shale oil 
     recovery process that uses in situ heating and avoids mining 
     and massive materials handling. Little is known about the 
     process and its economics, so its potential cannot now be 
     evaluated. (See Appendix VI for notes on shale oil).
       Biomass can be grown, collected and converted to substitute 
     liquid fuels by a number of processes. Currently, biomass-to-
     ethanol is produced on a large scale to provide a gasoline 
     additive. The market for ethanol derived from biomass is 
     influenced by federal requirements and facilitated by 
     generous federal and state tax subsidies. Research holds 
     promise of more economical ethanol production from cellulosic 
     (``woody'') biomass, but related processes are far from 
     economical. Reducing the cost of growing, harvesting, and 
     converting biomass crops will be necessary. In other parts of 
     the world, biomass-to-liquid fuels might be more attractive, 
     depending on a myriad of factors, including local labor 
     costs. Related projections for large-scale production would 
     be strictly speculative. In summary, there are no developed 
     biomass-to-fuels technologies that are now near cost 
     competitive. (See Appendix VI for notes on biomass).


                    F. Fuel Switching to Electricity

       Electricity is only used to a limited extent in the 
     transportation sector. Diesel fuels (mid-distillates) power 
     most rail trains in the U.S.; only a modest fraction are 
     electric powered. Other electric transportation is limited to 
     special situations, such as forklifts, in-factory 
     transporters, etc.
       In the 1990s electric automobiles were introduced to the 
     market, spurred by a California clean vehicle requirement. 
     The effort was a failure because existing batteries did not 
     provide the vehicle range and performance that customers 
     demanded. In the future, electricity storage may improve 
     enough to win consumer acceptance of electric automobiles. In 
     addition, extremely high gasoline prices may cause some 
     consumers to find electric automobiles more acceptable, 
     especially for around-town use. Such a shift in public 
     preferences is unpredictable, so electric vehicles cannot now 
     be projected as a significant offset to future gasoline use.

[[Page 26530]]

       A larger number of train routes could be outfitted for 
     electric trains, but such a transition would likely be slow, 
     because of the need to build additional electric power 
     plants, transmission lines, and electric train cars. Since 
     existing diesel locomotives use electric drive, their 
     retrofit might be feasible. However, since diesel fuel use in 
     trains is only roughly 0.3 MM bpd, electrification of trains 
     would not have a major impact on U.S liquid fuel consumption.
       There are no known near-commercial means for electrifying 
     heavy trucks or aircraft, so related conversions are not now 
     foreseeable.


                        G. Other Fuel Switching

       It is conceivable that consumers who now use mid-
     distillates and LPG (Liquefied Petroleum Gas) for heating 
     could switch to natural gas or electricity, thereby freeing 
     up liquid fuels for transportation. Analysis of this path is 
     beyond the scope of this study, but it should be noted that 
     these uses represent only a few percent of U.S. liquid fuel 
     consumption. Such switching on a large scale would require 
     the construction of compensating natural gas and/or electric 
     power facilities and infrastructure, which would not happen 
     quickly. In addition, freed-up liquids would likely require 
     further refining to meet market and environmental 
     requirements. Related refining would require refinery 
     construction, which would also be time consuming.


                              H. Hydrogen

       Hydrogen has potential as a long-term alternative to 
     petroleum-based liquid fuels in some transportation 
     applications. Like electricity, hydrogen is an energy 
     carrier; hydrogen production requires an energy source for 
     its production. Energy sources for hydrogen production 
     include natural gas, coal, nuclear power, and renewables. 
     Hydrogen can be used in internal combustion engines, similar 
     to those in current use, or via chemical reactions in fuel 
     cells.
       The Department of Energy is currently conducting a high 
     profile program aimed at developing a ``hydrogen economy.'' 
     DOE's primary emphasis is on hydrogen for light duty vehicle 
     application (automobiles and light duty trucks). Recently, 
     the National Research Council (NRC) completed a study that 
     included an evaluation of the technical, economic and 
     societal challenges associated with the development of a 
     hydrogen economy. That study is the basis for the following 
     highlights.
       A lynchpin of the current DOE hydrogen program is fuel 
     cells. In order for fuel cells to compete with existing 
     petroleum-based internal combustion engines, particularly for 
     light duty vehicles, the NRC concluded that fuel cells must 
     improve by (1) a factor of 10-20 in cost, (2) a factor of 
     five in lifetime, and (3) roughly a factor of two in 
     efficiency. The NRC did not believe that such improvements 
     could be achieved by technology development alone; instead, 
     new concepts (breakthroughs) will be required. In other 
     words, today's technologies do not appear practically viable.
       Because of the need for unpredictable inventions in fuel 
     cells, as well as viable means for on-board hydrogen storage, 
     the introduction of commercial hydrogen vehicles cannot be 
     predicted.


                    I. Factors That Can Cause Delay

       It is extremely difficult, expensive, and time consuming to 
     construct any type of major energy-related facility in the 
     U.S. today. Even assuming the expenditure of substantial time 
     and money, it is not certain that many proposed facilities 
     will ever be constructed. The construction of transmission 
     lines, interim and permanent nuclear waste disposal 
     facilities, electric generation plants, waste incinerators, 
     oil refineries, LNG terminals, waste recycling facilities, 
     petrochemical plants, etc. is increasingly problematic.
       What used to be termed the ``not-in-my-back-yard'' (NIMBY) 
     principle has evolved into the ``build-absolutely-nothing-
     anywhere-near-anything'' (BANANA) principle, which is 
     increasingly being applied to facilities of any type, 
     including low-income housing, cellular phone towers, prisons, 
     sports stadiums, water treatment facilities, airports, 
     hazardous waste facilities, and even new fire houses. 
     Construction of even a single, relatively innocuous, urgently 
     needed facility can easily take more than a decade. For 
     example, in 1999, King County, Washington, initiated the 
     siting process for the Brightwater wastewater treatment 
     plant, which it hopes to have operational in 2010.
       The routine processes required for siting energy facilities 
     can be daunting, expensive, and time consuming, and if a 
     facility is at all controversial, which is almost invariably 
     the case, opponents can often extend the permitting process 
     until sponsors terminate their plans. For example, approval 
     for new, small, distributed energy systems requires a minimum 
     of 18 separate steps, requiring approval from four federal 
     agencies, 11 state government agencies, and 14 local 
     government agencies. Opponents of energy facilities routinely 
     exercise their right to raise objections and offer 
     alternatives. Intervenors in permitting processes may delay 
     decisions and in some cases force outright cancellations, 
     although cases do exist in which facilities have been sited 
     quickly.
       The implications for U.S. homeland-based mitigation of 
     world oil peaking are troubling. To replace dwindling 
     supplies of conventional oil, large numbers of expensive and 
     environmentally intrusive substitute fuel production 
     facilities will be required. Under current conditions, it 
     could easily require more than a decade to construct a large 
     coal liquefaction plant in the U.S. The prospects for 
     constructing 25-50, with the first ones coming into operation 
     within a three year time window are essentially nil. Absent 
     change, the U.S. may end up on the path of least resistance, 
     allowing only a few substitute fuels plants to be built on 
     U.S. soil; in the process the U.S. would be adding substitute 
     fuel imports to its increasing dependence on imports of 
     conventional oil.
       For the U.S. to attain a lower level of dependence on 
     liquid fuel imports after the advent of world oil peaking, a 
     major paradigm shift will be required in the current approach 
     to the construction of capital-intensive energy facilities. 
     Federal and state governments will have to adopt legislation 
     allowing the acceleration of the development of substitute 
     fuels projects from current decade time-scales. During World 
     War II, facilities of all types were constructed on a scale 
     and schedules that would have previously been inconceivable. 
     In the face of the 1973 energy crisis, the Alaska oil 
     pipeline was approved and constructed in record time.
       While world oil peaking poses many dangers for the U.S., it 
     also offers substantial opportunities. The U.S. could emerge 
     as the world's largest producer of substitute liquid fuels, 
     if it were to undertake a massive program to construct 
     substitute fuel production facilities on a timely basis. The 
     nation is ideally positioned to do so because it has the 
     world's largest coal reserves, and it could muster the 
     required capital, technology, and labor to implement such a 
     program. However, unless a process is developed to expedite 
     plant construction, this opportunity could easily slip away. 
     Other nations, such as China, India, Japan, Korea, and others 
     also have the capabilities needed to construct and operate 
     such plants. Under current conditions, other countries are 
     able to bring such large energy projects on-line much more 
     rapidly than the U.S. Such countries could conceivably even 
     import U.S. coal, convert it to liquid fuels products, and 
     then export finished product back to the U.S. and elsewhere.
       The U.S. has well-developed coal mining, transportation, 
     and shipping systems that move coal to the highest bidders, 
     be they domestic or international. As recently as 1981, 14 
     percent of U.S. coal production was exported. While that 
     number has declined in recent years, the U.S. could easily 
     expand its current coal exports many fold to provide 
     feedstock for coal liquefaction plants in other nations. Not 
     only would the U.S. be dependent on foreign sources for 
     conventional oil, which will continue to dwindle in volume 
     after peaking, but it could also become dependent on foreign 
     sources for substitute fuels derived from U.S. coal.

                          VII. A World Problem

       Oil is essential to all countries. In 2002 daily 
     consumption ranged from almost 20 million barrels in the U.S. 
     to 20 barrels in the tiny South Pacific island of Niue, 
     population 2,400.
       Oil is produced in 123 countries. The top 20 producing 
     countries provide over 83 percent of total world oil. 
     Production by the largest producers is shown in Table VII-1. 
     The table also lists the top 20 oil-consuming countries and 
     their respective consumption. In total, the top 20 countries 
     consume over 75 percent of the average daily production. 
     Beyond these larger consumers, oil is also utilized in all 
     the world's 194 remaining countries.

   TABLE VII.1--TOP WORLD OIL PRODUCING AND CONSUMING COUNTRIES--2002
------------------------------------------------------------------------
          Rank                    Country             MM bpd    Percent
------------------------------------------------------------------------
                                Producers
 
1......................  United States............        9.0       11.7
2......................  Saudi Arabia.............        8.7       11.3
3......................  Russia...................        7.7       10.0
4......................  Mexico...................        3.6        4.7
5......................  Iran.....................        3.5        4.6
6......................  China....................        3.5        4.6
7......................  Norway...................        3.3        4.3
8......................  Canada...................        2.9        3.8
9......................  Venezuela................        2.9        3.8
10.....................  United Kingdom...........        2.6        3.3
11.....................  United Arab Emirates.....        2.4        3.1
12.....................  Nigeria..................        2.1        2.8
13.....................  Iraq.....................        2.0        2.7
14.....................  Kuwait...................        2.0        2.6
15.....................  Brazil...................        1.8        2.3
16.....................  Algeria..................        1.6        2.0
17.....................  Libya....................        1.4        1.8
18.....................  Indonesia................        1.4        1.8
19.....................  Kazakhstan...............        0.9        1.2
20.....................  Oman.....................        0.9        1.2
                         103 other countries......       12.6       16.3
 
                                Consumers
 
1......................  United States............       19.8       25.3
2......................  Japan....................        5.3        6.8
3......................  China....................        5.2        6.6
4......................  Germany..................        2.7        3.5
5......................  Russia...................        2.6        3.3
6......................  India....................        2.2        2.8
7......................  Korea, South.............        2.2        2.8
8......................  Brazil...................        2.2        2.8
9......................  Canada...................        2.1        2.7
10.....................  France...................        2.0        2.5
11.....................  Mexico...................        2.0        2.5
12.....................  Italy....................        1.8        2.4
13.....................  United Kingdom...........        1.7        2.2
14.....................  Saudi Arabia.............        1.5        1.9
15.....................  Spain....................        1.5        1.9
16.....................  Iran.....................        1.3        1.7
17.....................  Indonesia................        1.1        1.4
18.....................  Taiwan...................        0.9        1.2

[[Page 26531]]

 
19.....................  Netherlands..............        0.9        1.1
20.....................  Australia................        0.9        1.1
                         194 other countries......       18.4       23.5
------------------------------------------------------------------------

                    VIII. Three Mitigation Scenarios


                            a. introduction

       Issues related to the peaking of world oil production are 
     extremely complex, involve literally trillions of dollars and 
     are very time-dependent. To explore these matters, we 
     selected three mitigation scenarios for analysis: Scenario I 
     assumes that action is not initiated until peaking occurs. 
     Scenario II assumes that action is initiated 10 years before 
     peaking. Scenario III assumes action is initiated 20 years 
     before peaking.
       Our approach is simplified in order to provide transparency 
     and promote understanding. Our estimates are approximate, but 
     the mitigation envelope that results is believed to be 
     indicative of the realities of such an enormous undertaking.


                         b. mitigation options

       Our focus is on large-scale, physical mitigation, as 
     opposed to policy actions, e.g. tax credits, rationing, 
     automobile speed restrictions, etc. We define physical 
     mitigation as (1) implementation of technologies that can 
     substantially reduce the consumption of liquid fuels 
     (improved fuel efficiency) while still delivering comparable 
     service and (2) the construction and operation of facilities 
     that yield large quantities of liquid fuels.


                         c. mitigation phase-in

       The pace that governments and industry chose to mitigate 
     the negative impacts of the peaking of world oil production 
     is to be determined. As a limiting case, we choose overnight 
     go-ahead decision-making for all actions, i.e., crash 
     programs. Our rationale is that in a sudden disaster 
     situation, crash programs are most likely to be quickly 
     implemented. Overnight go-ahead decision-making is most 
     probable in our Scenario I, which assumes no action prior to 
     the onset of peaking. By assuming overnight implementation in 
     all three of our scenarios, we avoid the arduous and 
     potentially arbitrary challenge of developing a more likely, 
     real world decision-making sequence. This is obviously an 
     optimistic assumption because government and corporate 
     decision-making is never instantaneous.


                          d. the use of wedges

       The model chosen to illustrate the possible effects of 
     likely mitigation actions involves the use of ``delayed 
     wedges'' to approximate the scale and pace of each action. 
     The use of wedges was effectively utilized in a recent paper 
     by Pacala and Socolow.
       Our wedges are composed of two parts. The first is the 
     preparation time needed prior to tangible market penetration. 
     In the case of efficient transportation, this time is 
     required to redesign vehicles and retool factories to produce 
     more efficient vehicles. In the case of the production of 
     substitute fuels, the delay is associated with planning and 
     construction of relevant facilities.
       After the preparation phase, our wedges then approximate 
     the penetration of mitigation effects into the marketplace. 
     This might be the growing sales of more fuel-efficient 
     vehicles or the growing production of substitute fuels. We 
     assume our wedges continue to expand for a few decades, which 
     simplifies illustration but is increasingly less realistic 
     over time because markets will adjust and impact rates will 
     change.
       Our aim is to approximate reality in a simple manner. 
     Greater detail is beyond the scope of this study and would 
     require in-depth analysis.


                    e. criteria for wedge selection

       Our criteria for selecting candidates for our energy saving 
     and substitute oil production wedges were as follows:
       1. The option must produce liquid fuels that can, as 
     produced or as refined, substitute for liquid fuels currently 
     in widespread use, e.g. gasoline, jet fuel, diesel, etc. The 
     end products will thus be compatible with existing 
     distribution systems and end-use equipment.
       2. The option must be capable of liquid fuels savings or 
     production on a massive scale--ultimately millions to tens of 
     millions of barrels per day worldwide.
       3. The option must include technology that is commercial or 
     near commercial, which at a minimum requires that the process 
     has been demonstrated at commercial scale. For production 
     technologies, this means that at least one plant has operated 
     at greater than 10,000 bpd for at least two years, and 
     product prices from the process are less than $50/barrel in 
     2004 dollars. For fuels efficiency technologies, the 
     technology must have at least entered the commercial market 
     by 2004.
       4. Substitute fuel production technologies must be 
     inherently energy efficient, which we assume to mean that 
     greater than 50 percent of process energy input is contained 
     in the clean liquid fuels product.
       5. The option must be environmentally clean by 2004 
     standards.
       6. While domestic resources are of greatest interest to the 
     U.S., the oil market is international, so substitute fuel 
     feedstocks not abundantly available in the U.S. must also be 
     considered, e.g. heavy oil/tar sands and gas-to-liquids.
       7. Energy sources or energy efficiency technologies that 
     produce or save electricity are not of interest in this 
     context because commercial processes to convert electricity 
     to clean hydrocarbon fuels do not currently exist.


                    F. Wedges Selected and Rejected

       The combination of technologies, processes, and feedstocks 
     that meet these criteria are as follows: 1. Fuel efficient 
     transportation; 2. Heavy oil/Oil sands; 3. Coal liquefaction; 
     4. Enhanced oil recovery; 5. Gas-to-liquids.
       In the end-use category, a dramatic increase in the 
     efficiency of petroleum-based fuel equipment is one 
     attractive option. As previously described, the imposition of 
     CAFE requirements for automobiles in 1975 was one of the most 
     effective of the government mandates initiated in response to 
     the 1973-74 oil embargo. In recent years, fuel economy for 
     automobiles has not been a high national priority in the U.S. 
     Nevertheless, a new hybrid engine technology has been phasing 
     into the automobile and truck markets. In a period of 
     national oil emergency, hybrid technology could be massively 
     implemented for new vehicle applications. Hybrid technologies 
     offer fuel economy improvements of 40 percent or more for 
     automobiles and light-medium trucks--no other engine 
     technologies offer such large, near-term fuel economy 
     benefits.
       The fuels production options that we chose are heavy oil/
     tar sands, coal liquefaction, improved oil recovery, and gas-
     to-liquids. Our rationale was as follows: 1. Enhanced Oil 
     Recovery is applicable worldwide; 2. Heavy oil/tar sands is 
     currently commercial in Canada and Venezuela; 3. Coal 
     liquefaction is a well-developed, near-commercial technology; 
     4. Gas-To-Liquids is commercially applicable where natural 
     gas is remote from markets.
       We excluded a number of options for various reasons. While 
     the U.S. has a huge resource of shale oil that could be 
     processed into substitute liquid fuels, the technology to 
     accomplish that task is not now ready for deployment. Because 
     various shale oil processing prototypes were developed in 
     years past and because shale oil processing is likely to be 
     economically attractive, a concerted effort to develop shale 
     oil technology could well lead to shale oil becoming a 
     contributor in Scenarios II or III. However, that would 
     require the initiation of a major R&D program in the near 
     future.
       Biomass options capable of producing liquid fuels were also 
     excluded. Ethanol from biomass is currently utilized in the 
     transportation market, not because it is commercially 
     competitive, but because it is mandated and highly 
     subsidized. Biodiesel fuel is a subject of considerable 
     current interest but it too is not yet commercially viable. 
     Again, a major R&D effort might change the biomass outlook, 
     if initiated in the near future.
       Over 45 percent of world oil consumption is for non-
     transportation uses. Fuel switching away from non-
     transportation uses of liquid fuels is likely to occur, 
     mimicking shifts that have already taken place in the U.S. 
     The time frame for such shifts is uncertain. For significant 
     world scale impact, alternate large energy facilities would 
     have to be constructed to provide the substitute energy, and 
     that facility construction would require the kind of decade-
     scale time periods required for oil peaking mitigation.
       Nuclear power, wind and photovoltaics produce electric 
     power, which is not a near-term substitute fuel in 
     transportation equipment that requires liquid fuels. In the 
     many-decade future after oil peaking, it is conceivable that 
     a massive shift from liquid fuels to electricity might occur 
     in some applications. However, consideration of such changes 
     would be speculative at this time.
       It is possible that technology innovations resulting from 
     aggressive future research may well change the outlook for 
     various technologies in the future. Our focus on the 
     currently viable is in no way intended to prejudice other 
     future options. We have chosen not to add a wedge for 
     undefined technologies that might result from accelerated 
     research, because such a wedge would be purely speculative. 
     No matter what the new technology(ies), implementation delay 
     times and contribution growth rates will inherently be of the 
     same order of magnitude of the technologies that we have 
     considered, because of the inherent scale of all physical 
     mitigation.


                  G. Modeling World Oil Supply/Demand

       It is not possible to predict with certainty when world 
     conventional oil peaking will occur or how rapidly production 
     will decline after the peak. To develop our scenarios, we 
     utilize the U.S. Lower 48 production pattern as a surrogate 
     for the world. This assumption is justified on the basis that 
     Lower 48 oil production represents what really happened in a 
     large, complex oil province over the course of decades of 
     modern oil production development.
       Our horizontal axis is centered on the year of peaking (the 
     date is not specified) and spans plus and minus two decades. 
     For this study, our vertical axis is pegged at a peak world 
     oil production of 100 MM bpd, which is 18 MM bpd above the 
     current 82 MM bpd world production. If peaking were to occur 
     soon, 100 MM bpd might be high by 20 percent. If peaking were 
     to occur at 125 MM bpd

[[Page 26532]]

     at some future date, the 100 MM bpd assumption would be low 
     by 20 percent. Since the estimates in our wedges are rough 
     under any conditions, a 100 MM bpd peak represents a credible 
     assumption for this kind of analysis. The selection of 100 MM 
     bpd is not intended as a prediction of magnitude or timing; 
     its use is for illustration purposes only.
       Next is the important issue of the slopes of the production 
     profile showing the rate of growth of production/demand 
     before peaking and the subsequent decline in production. The 
     World Energy Council stated: ``Oil demand is projected to 
     increase at about 1.9 percent per year rising from about 75.7 
     million b/d in 2000 (actual) to 113-115 million b/d in 2020--
     an increase of about 37.5-39.5 million b/d.'' Recent trends 
     indicate a 3+ percent world oil demand growth, driven in part 
     by rapidly increasing oil consumption in China and India. 
     However, a 3+ percent growth rate on a continuing basis seems 
     excessive. On this basis, we assume a two percent demand 
     growth before peaking, and we assume an intrinsic two percent 
     long-run hypothetical, healthy economy demand after peaking. 
     This extrapolation of demand after peaking provides a 
     reference that facilitates calculation of supply shortfalls. 
     The assumption has the benefit of simplicity, but it ignores 
     the real-world feedback of oil price escalation on demand, 
     which is sure to happen but the calculation thereof will be 
     complicated and was beyond the scope of this study.
       Estimating a decline rate after world oil production 
     peaking is a difficult issue. While human activity dominates 
     the demand for oil, the ``rocks'' (geology) will dominate the 
     decline of world conventional oil production after peaking. 
     Referring to U.S. Lower 48 production history, the decline 
     after the 1970 peaking was roughly 1.7 percent per year, 
     which we have chosen to round off to two percent per year as 
     our estimated world conventional oil decline rate. It should 
     be noted that other analysts have projected decline rates of 
     3-8%, which would make the mitigation problem much more 
     difficult.


                             H. Our Wedges

       In Appendix IV we develop the sizes of the wedges that we 
     believe appropriate for our trends analysis. Once again, bear 
     in mind that these are rough approximations aimed at 
     illustrating the inherently large scale of mitigation.


                         I. The Three Scenarios

       As noted, our three scenarios are benchmarked to the 
     unknown date of peaking: Scenario I: Mitigation begins at the 
     time of peaking; Scenario II: Mitigation starts 10 years 
     before peaking; Scenario III: Mitigation starts 20 years 
     before peaking.
       Our mitigation choices then map onto our assumed world oil 
     peaking pattern.


               Observations and Conclusions on Scenarios

       This exercise was conducted bottom-up; we estimated 
     reasonable potential contributions from each viable option, 
     summed them, and then applied them to our assumed world oil 
     peaking pattern.
       While our option contribution estimates are clearly 
     approximate, in total they probably represent a realistic 
     portrayal of what might be achieved with an array of physical 
     mitigation options. Together, implementation of all of the 
     specified options would provide 15-20 MM bpd impact, ten 
     years after simultaneous initiation. Roughly 90 percent would 
     result from substitute liquid fuel production and roughly ten 
     percent would come from transportation fuel efficiency 
     improvements.
       Our results are congruent with the fundamentals of the 
     problem: Waiting until world oil production peaks before 
     taking crash program action leaves the world with a 
     significant liquid fuel deficit for more than two decades. 
     Initiating a mitigation crash program 10 years before world 
     oil peaking helps considerably but still leaves a liquid 
     fuels shortfall roughly a decade after the time that oil 
     would have peaked. Initiating a mitigation crash program 20 
     years before peaking appears to offer the possibility of 
     avoiding a world liquid fuels shortfall for the forecast 
     period.
       The obvious conclusion from this analysis is that with 
     adequate, timely mitigation, the costs of peaking can be 
     minimized. If mitigation were to be too little, too late, 
     world supply/demand balance will be achieved through massive 
     demand destruction (shortages), which would translate to 
     significant economic hardship, as discussed earlier.


                           K. Risk Management

       It is possible that peaking may not occur for several 
     decades, but it is also possible that peaking may occur in 
     the near future. We are thus faced with a daunting risk 
     management problem:
       On the one hand, mitigation initiated soon would be 
     premature if peaking is still several decades away.
       On the other hand, if peaking is imminent, failure to 
     initiate mitigation quickly will have significant economic 
     and social costs to the U.S. and the world.
       The two risks are asymmetric: Mitigation actions initiated 
     prematurely will be costly and could result in a poor use of 
     resources. Late initiation of mitigation may result in severe 
     consequences.
       The world has never confronted a problem like this, and the 
     failure to act on a timely basis could have debilitating 
     impacts on the world economy. Risk minimization requires the 
     implementation of mitigation measures well prior to peaking. 
     Since it is uncertain when peaking will occur, the challenge 
     is indeed significant.

              IX. Market Signals As Peaking Is Approached

       As world oil peaking is approached and demand for 
     conventional oil begins to exceed supply, oil prices will 
     rise steeply. As discussed in Chapter IV, related price 
     increases are almost certain to have negative impacts on the 
     U.S. and world economies. Another likely signal is 
     substantially increased oil price volatility.
       Oil prices have traditionally been volatile. Causes include 
     political events, weather, labor strikes, infrastructure 
     problems, and fears of terrorism. In an era where supply was 
     adequate to meet demand and where there was excess production 
     capacity in OPEC, those effects were relatively short-lived. 
     However, as world oil peaking is approached, excess 
     production capacity by definition will disappear, so that 
     even minor supply disruptions will cause increased price 
     volatility as traders, speculators, and other market 
     participants react to supply/demand events. Simultaneously, 
     oil storage inventories are likely to decrease, further 
     eroding security of supply, aggravating price volatility, and 
     further stimulating speculation.
       While it is recognized that high oil prices will have 
     adverse effects, the effects of increased price volatility 
     may not be sufficiently appreciated. Higher oil price 
     volatility can lead to reduction in investment in other parts 
     of the economy, leading in turn to a long-term reduction in 
     supply of various goods, higher prices, and further reduced 
     macroeconomic activity. Increasing volatility has the 
     potential to increase both economic disruption and 
     transaction costs for both consumers and producers, adding to 
     inflation and reducing economic growth rates.
       The most relevant experience was during the 1970s and early 
     1980s, when oil prices increased roughly six-fold and oil 
     price volatility was aggravated. Those reactions have often 
     been dismissed as a ``panic response,'' but that experience 
     may nevertheless be a good indicator of the oil price 
     volatility to be expected when demand exceeds supply after 
     oil peaking.
       The factors that cause oil price escalation and volatility 
     could be further exacerbated by terrorism. For example, in 
     the summer of 2004, it was estimated that the threat of 
     terrorism had added a premium of 25-33 percent to the price 
     of a barrel of oil. As world oil peaking is approached, it is 
     not difficult to imagine that the terrorism premium could 
     increase even more.
       In conclusion, oil peaking will not only lead to higher oil 
     prices but also to increased oil price volatility. In the 
     process, oil could become the price setter in the broader 
     energy market, in which case other energy prices could well 
     become increasingly volatile and unpredictable.

                              X. Wildcards

       There are a number of factors that could conceivably impact 
     the peaking of world oil production. Here is a list of 
     possible upsides and downsides.


  A. Upsides--Things That Might Ease the Problem of World Oil Peaking

       The pessimists are wrong again and peaking does not occur 
     for many decades.
       Middle East oil reserves are much higher than publicly 
     stated.
       A number of new super-giant oil fields are found and 
     brought into production, well before oil peaking might 
     otherwise have occurred.
       High world oil prices over a sustained period (a decade or 
     more) induce a higher level of structural conservation and 
     energy efficiency.
       The U.S. and other nations decide to institute 
     significantly more stringent fuel efficiency standards well 
     before world oil peaking.
       World economic and population growth slows and future 
     demand is much less than anticipated.
       China and India decide to institute vehicle efficiency 
     standards and other energy efficiency requirements, reducing 
     the rate of growth of their oil requirements.
       Oil prices stay at a high enough level on a sustained basis 
     so that industry begins construction of substitute fuels 
     plants well before oil peaking.
       Huge new reserves of natural gas are discovered, a portion 
     of which is converted to liquid fuels.
       Some kind of scientific breakthrough comes into commercial 
     use, mitigating oil demand well before oil production peaks.


  B. Downsides--Things That Might Exacerbate the Problem of World Oil 
                                Peaking

       World oil production peaking is occurring now or will 
     happen soon.
       Middle East reserves are much less than stated.
       Terrorism stays at current levels or increases and 
     concentrates on damaging oil production, transportation, 
     refining and distribution.
       Political instability in major oil producing countries 
     results in unexpected, sustained world-scale oil shortages.
       Market signals and terrorism delay the realization of 
     peaking, delaying the initiation of mitigation.

[[Page 26533]]

       Large-scale, sustained Middle East political instability 
     hinders oil production.
       Consumers demand even larger, less fuel-efficient cars and 
     SUVs.
       Expansion of energy production is hindered by increasing 
     environmental challenges, creating shortages beyond just 
     liquid fuels.

                   XI. Summary and Concluding Remarks

       Our analysis leads to the following conclusions and final 
     thoughts.


                1. World Oil Peaking is Going to Happen

       World production of conventional oil will reach a maximum 
     and decline thereafter. That maximum is called the peak. A 
     number of competent forecasters project peaking within a 
     decade; others contend it will occur later. Prediction of the 
     peaking is extremely difficult because of geological 
     complexities, measurement problems, pricing variations, 
     demand elasticity, and political influences. Peaking will 
     happen, but the timing is uncertain.


           2. Oil Peaking Could Cost the U.S. Economy Dearly

       Over the past century the development of the U.S. economy 
     and lifestyle has been fundamentally shaped by the 
     availability of abundant, low-cost oil. Oil scarcity and 
     several-fold oil price increases due to world oil production 
     peaking could have dramatic impacts. The decade after the 
     onset of world oil peaking may resemble the period after the 
     1973-74 oil embargo, and the economic loss to the United 
     States could be measured on a trillion-dollar scale. 
     Aggressive, appropriately timed fuel efficiency and 
     substitute fuel production could provide substantial 
     mitigation.


               3. Oil Peaking Presents a Unique Challenge

       The world has never faced a problem like this. Without 
     massive mitigation more than a decade before the fact, the 
     problem will be pervasive and will not be temporary. Previous 
     energy transitions (wood to coal and coal to oil) were 
     gradual and evolutionary; oil peaking will be abrupt and 
     revolutionary.


                     4. The Problem is Liquid Fuels

       Under business-as-usual conditions, world oil demand will 
     continue to grow, increasing approximately two percent per 
     year for the next few decades. This growth will be driven 
     primarily by the transportation sector. The economic and 
     physical lifetimes of existing transportation equipment are 
     measured on decade time-scales. Since turnover rates are low, 
     rapid changeover in transportation end-use equipment is 
     inherently impossible.
       Oil peaking represents a liquid fuels problem, not an 
     ``energy crisis'' in the sense that term has been used. Motor 
     vehicles, aircraft, trains, and ships simply have no ready 
     alternative to liquid fuels. Non-hydrocarbon-based energy 
     sources, such as solar, wind, photovoltaics, nuclear power, 
     geothermal, fusion, etc. produce electricity, not liquid 
     fuels, so their widespread use in transportation is at best 
     decades away. Accordingly, mitigation of declining world oil 
     production must be narrowly focused.


          5. Mitigation Efforts Will Require Substantial Time

       Mitigation will require an intense effort over decades. 
     This inescapable conclusion is based on the time required to 
     replace vast numbers of liquid fuel consuming vehicles and 
     the time required to build a substantial number of substitute 
     fuel production facilities. Our scenarios analysis shows:
       Waiting until world oil production peaks before taking 
     crash program action would leave the world with a significant 
     liquid fuel deficit for more than two decades.
       Initiating a mitigation crash program 10 years before world 
     oil peaking helps considerably but still leaves a liquid 
     fuels shortfall roughly a decade after the time that oil 
     would have peaked.
       Initiating a mitigation crash program 20 years before 
     peaking appears to offer the possibility of avoiding a world 
     liquid fuels shortfall for the forecast period.
       The obvious conclusion from this analysis is that with 
     adequate, timely mitigation, the economic costs to the world 
     can be minimized. If mitigation were to be too little, too 
     late, world supply/demand balance will be achieved through 
     massive demand destruction (shortages), which would translate 
     to significant economic hardship.
       There will be no quick fixes. Even crash programs will 
     require more than a decade to yield substantial relief.


            6. Both Supply and Demand Will Require Attention

       Sustained high oil prices will stimulate some level of 
     forced demand reduction. Stricter end-use efficiency 
     requirements can further reduce embedded demand, but 
     substantial, world-scale change will require a decade or 
     more. Production of large amounts of substitute liquid fuels 
     can and must be provided. A number of commercial or near-
     commercial substitute fuel production technologies are 
     currently available, so the production of large amounts of 
     substitute liquid fuels is technically and economically 
     feasible, albeit time-consuming and expensive.


                  7. It Is a Matter of Risk Management

       The peaking of world conventional oil production presents a 
     classic risk management problem: Mitigation efforts initiated 
     earlier than required may turn out to be premature, if 
     peaking is long delayed. On the other hand, if peaking is 
     imminent, failure to initiate timely mitigation could be 
     extremely damaging.
       Prudent risk management requires the planning and 
     implementation of mitigation well before peaking. Early 
     mitigation will almost certainly be less expensive and less 
     damaging to the world's economies than delayed mitigation.


              8. Government Intervention Will be Required

       Intervention by governments will be required, because the 
     economic and social implications of oil peaking would 
     otherwise be chaotic. The experiences of the 1970s and 1980s 
     offer important lessons and guidance as to government actions 
     that might be more or less desirable. But the process will 
     not be easy. Expediency may require major changes to existing 
     administrative and regulatory procedures such as lengthy 
     environmental reviews and lengthy public involvement.


                 9. Economic Upheaval is Not Inevitable

       Without mitigation, the peaking of world oil production 
     will almost certainly cause major economic upheaval. However, 
     given enough lead-time, the problems are soluble with 
     existing technologies. New technologies are certain to help 
     but on a longer time scale. Appropriately executed risk 
     management could dramatically minimize the damages that might 
     otherwise occur.


                     10. More Information is Needed

       The most effective action to combat the peaking of world 
     oil production requires better understanding of a number of 
     issues. Is it possible to have relatively clear signals as to 
     when peaking might occur? It would be desirable to have 
     potential mitigation actions better defined with respect to 
     cost, potential capacity, timing, etc. Various risks and 
     possible benefits of possible mitigation actions need to be 
     examined. (See Appendix V for a list of possible follow-on 
     studies).
       The purpose of this analysis was to identify the critical 
     issues surrounding the occurrence and mitigation of world oil 
     production peaking. We simplified many of the complexities in 
     an effort to provide a transparent analysis. Nevertheless, 
     our study is neither simple nor brief. We recognize that when 
     oil prices escalate dramatically, there will be demand and 
     economic impacts that will alter our simplified analysis. 
     Consideration of those feedbacks will be a daunting task but 
     one that should be undertaken.
       Our study required that we make a number of assumptions and 
     estimates. We well recognize that in-depth analyses may yield 
     different numbers. Nevertheless, this analysis clearly 
     demonstrates that the key to mitigation of world oil 
     production peaking will be the construction a large number of 
     substitute fuel production facilities, coupled to significant 
     increases in transportation fuel efficiency. The time 
     required to mitigate world oil production peaking is measured 
     on a decade time-scale, and related production facility size 
     is large and capital intensive. How and when governments 
     decide to address these challenges is yet to be determined.
       Our focus on existing commercial and near-commercial 
     mitigation technologies illustrates that a number of 
     technologies are currently ready for immediate and extensive 
     implementation. Our analysis was not meant to be limiting. We 
     believe that future research will provide additional 
     mitigation options, some possibly superior to those we 
     considered. Indeed, it would be appropriate to greatly 
     accelerate public and private oil peaking mitigation 
     research. However, the reader must recognize that doing the 
     research required to bring new technologies to commercial 
     readiness takes time under the best of circumstances. 
     Thereafter, more than a decade of intense implementation will 
     be required for world scale impact, because of the inherently 
     large scale of world oil consumption.

                            Acknowledgements

       This work was sponsored by the National Energy Technology 
     Laboratory of the Department of Energy, under Contracts No. 
     DE-AM26-99FT40575, Task 21006W and Subcontract Agreement 
     number 7010001197 with Energy and Environmental Solutions, 
     LLC. The authors are indebted to NETL management for their 
     encouragement and support.

                               Appendices

       I.  Most Meaningful EIA Oil Peaking Case
       II.  More Historical Oil Crisis Considerations
       III.  Likely Future Oil Demand
       IV.  Rationales for the Wedges
       A.  Vehicle Efficiency Wedge
       B.  Coal Liquids
       C.  Heavy oils/Oil Sands
       D.  Improved Oil Recovery
       E.  Gas-To-Liquids
       F.  Sum of the Wedges
       V.  Notes on Shale Oil and Biomass
       VI.  Topics for Future Study

            Appendix I. Most Meaningful EIA Oil Peaking Case

       In the year 2000, EIA developed 12 scenarios for world oil 
     production peaking using three U.S. Geological Survey (USGS) 
     estimates of the world conventional oil resource base (Low, 
     Expected, and High) and four annual world oil demand growth 
     rates (0, 1, 2, and 3 percent per year). We believe the most 
     likely of the EIA scenarios is the one based on the

[[Page 26534]]

     USGS expected ultimate world recoverable oil of 3.003 billion 
     barrels coupled with 2% annual world oil demand escalation.
       The difference between the two profiles is attributable to 
     two assumed production decay rates following peak production. 
     Both curves assume a 2 percent per year growth from the year 
     2000 until the peak. One scenario assumes a 2 percent decline 
     after the world oil production peak, while the other assumes 
     a steeper drop after the world oil production peak. Because 
     the areas under both curves must equal the projected 3,003 
     billion barrels of recoverable conventional oil from the year 
     2000 forward, the rapid decay curve will inherently yield the 
     later occurring, higher world oil production peak.
       The EIA scenario that peaks in 2016 looks like the 
     relatively symmetric U.S. Lower 48 production profile. The 
     EIA scenario that peaks in 2037 not only differs dramatically 
     from the U.S. experience, it differs from typical individual 
     oil reservoir experience, which often displays a relatively 
     symmetric production profile, not the sharp drop illustrated 
     in the alternate EIA case. On this basis, we believe that the 
     EIA 2016 peaking case appears much more credible than the 
     2037 peaking case. The associated 21-year difference between 
     the two predicted production peaks clearly would have 
     profound implications for the time available for mitigation.
       It is worth noting that the USGS mean estimate for the 
     remaining recoverable world oil resource is much higher than 
     estimates made by other investigators, according to K.S. 
     Deffeyes, retired Shell geologist and emeritus Princeton 
     geology professor. Deffeyes also opined `` . . . in 2000 the 
     USGS again released implausibly large estimates of world 
     oil.'' A lower total reserves estimate would of course mean a 
     world oil production peak earlier than 2016.

         Appendix II. More Historical Oil Crisis Considerations

       Economists have debated whether the economic problems of 
     the 1970s were due to the oil supply disruptions or to 
     inappropriate fiscal, monetary, and energy policies 
     implemented to deal with them. The consensus is that the 
     disruptions would have caused economic problems irrespective 
     of fiscal, monetary, and energy policies, but that price and 
     allocation controls exacerbated the impacts in the U.S. 
     during the 1970s. There is general consensus on the 
     following:
       Appropriate actions taken included CAFE, the 55 mph speed 
     limit, reorganization of the Federal energy bureaucracy, 
     greatly increased energy R&D, establishment of the Strategic 
     Petroleum Reserve (SPR), energy efficiency standards and 
     building codes, establishment of IEA and EIA, and burden 
     sharing agreements among nations.
       Inadvisable actions included price and allocation controls, 
     excessive regulations, de-facto gasoline rationing, ``excess 
     profits'' taxes, policies targeting ``greedy energy 
     companies,'' prohibitions on energy use, and subsidy 
     programs.
       Some actions that seemed to be inappropriate may have been 
     desirable if the problem had not been short-lived. For 
     example, synthetic fuel initiatives may have looked prescient 
     had oil prices not collapsed in the mid 1980s.
       Estimated costs to the U.S. of oil supply disruptions range 
     from $25 billion to $75 billion per year, and the cumulative 
     costs since 1973-74 total about $4 trillion. Nevertheless, 
     except for several serious disruptions (and then only 
     temporarily), oil prices have risen little in real terms over 
     the past century.
       Cost of living adjustment clauses imbedded in many 
     contracts, labor agreements, and government programs (e.g., 
     Social Security) are less visible but important inflation 
     drivers. Price increases generated by oil supply disruptions 
     automatically trigger successive inflationary adjustments 
     throughout the economy, and these complicate monetary 
     policies designed to counter the inflationary effects of the 
     disruption.
       The U.S. is currently less oil-dependent (in terms of oil/
     GDP ratios) than during the 1970s. However, the U.S. is now 
     importing twice as much oil (in percentage terms) as 30 years 
     ago and its transportation sector consumes a larger portion 
     of total oil consumption. Further, by 2000 most of the energy 
     saving trends resulting from the 1970s disruptions (increased 
     energy efficiency and conservation, increased vehicle mpg, 
     etc.) had been captured.
       The primary effect of the 1973-74 disruption was oil price 
     increases. The real price of oil peaked in 1981 and has never 
     again reached similar levels.
       At present, oil would have to be nearly $80 per barrel and 
     gasoline would have to exceed $3 per gallon to equal real 
     1981 prices. Even then, however, energy would still be a less 
     significant factor in the U.S. economy because average U.S. 
     per capita incomes have doubled since 1981 and energy is a 
     much smaller component of expenditures.
       Nevertheless, over the past 50 years, oil prices have been 
     extremely volatile--more volatile than virtually any other 
     commodity.

                 Appendix III. Likely Future Oil Demand

       Petroleum consumption has been inexorably linked to 
     population growth, industrial development, and economic 
     growth for the past century. This relationship is expected to 
     continue worldwide for the foreseeable future. While the U.S. 
     consumes more oil than any other country--about 20 MM bpd, it 
     represents only 26 percent of world production, compared to 
     the 46 percent of world oil production the U.S. consumed in 
     1960. Western Europe currently consumes the second largest 
     amount (18 percent) followed by Japan (7 percent), China (6 
     percent), and the FSU (5 percent), with over 150 other 
     countries accounting for the remaining 38 percent of 
     production.
       Energy forecasting is difficult due to the numerous complex 
     factors that influence energy supply and demand. Here we 
     utilize the U.S. Energy Department's Energy Information 
     Administration forecasts of future world oil requirements.
       Table A-1 presents summary statistics for the EIA 2001-2025 
     forecast including 24-year country or country group 
     projections for petroleum consumption, gross domestic product 
     (GDP), and population.

                                TABLE A-1.--REFERENCE CASE PROJECTIONS, 2001-2025
                                       [Average annual percentage change]
----------------------------------------------------------------------------------------------------------------
                                                                  Petroleum
                                                                 consumption      GDP (Con. $)      Population
----------------------------------------------------------------------------------------------------------------
U.S..........................................................             1.5              3.0              0.8
W. Europe....................................................             0.5              2.0              0.1
China........................................................             4.0              6.1              0.5
FSU..........................................................             2.1              4.2             -0.2
Japan........................................................             0.3              1.7             -0.1
Other........................................................             2.0              4.0              1.3
                                                              --------------------------------------------------
    World....................................................             1.9              3.0              1.0
----------------------------------------------------------------------------------------------------------------

       Oil consumption in China is expected to increase 4 percent 
     a year, and by 2025 China is projected to be the second 
     largest oil consuming country in the world, accounting for 11 
     percent of total world consumption. The second fastest 
     growing market is projected to be the FSU countries, where 
     petroleum consumption is forecast to increase an average of 
     over 2 percent per year.
       The remaining large consumers, including the U.S., Western 
     Europe, and Japan are forecast to experience consumption 
     growth over the 24-year period at or below the world average. 
     The U.S. is forecast to increase oil consumption at a rate of 
     1.5 percent per year, and by 2025 the U.S. share of world oil 
     consumption is forecast to decline to 23 percent (29.7 MM 
     bpd), while Western Europe's share decreases to 13 percent 
     (14.4 MM bpd). The many countries grouped as ``Other'' above, 
     including India, Mexico, and Brazil, are expected to 
     experience oil consumption growth rates 10 to 30 percent 
     higher than the world average. By 2025, this group is 
     forecast to account for 43 percent of world oil consumption.
       In sum, in the EIA reference case, world oil consumption of 
     80 MM bpd in 2003 is projected to increase to 121 MM bpd in 
     2025, with the most rapid increases occurring in nations 
     other than the U.S., Japan, or those in Western Europe. 
     Average annual world oil demand growth is projected as 1.9 
     percent over the period.

                 Appendix IV. Rationales for the Wedges


                       A. Vehicle Fuel Efficiency

       The original U.S. Corporate Average Fuel Efficiency (CAFE) 
     timetable, enacted in 1975, mandated a 53 percent increase in 
     vehicle fuel efficiency, from 18 mpg to 27.5 mpg, over the 
     seven years between 1978 and 1985. Average on-road vehicle 
     fuel efficiency began to improve markedly in the early 1980s 
     and continued to improve substantially every year through 
     1995. It showed little change between 1995 and 1999, and then 
     began to decline gradually due to the shift to greater 
     purchases of light trucks and SUVs. Between 1982 and 1995, 
     average on-road vehicle fuel efficiency increased from about 
     14 mpg to 20 mpg. In other words, the first major U.S. oil 
     disruption occurred in the fall of 1973; CAFE was not enacted 
     until two years later; the increased mpg requirements did not 
     begin until 1978, and were phased in through 1985; and 
     significant increases in average on-road vehicle fuel 
     efficiency did not occur until the mid- to late 1980s.
       From the time world oil peaking occurs or is recognized, it 
     may thus take as long as 15 years until strengthened vehicle 
     fuel efficiency standards significantly increase average on-
     road fleet fuel efficiency. However, care must be exercised 
     in making extrapolations. Most ``realistic'' enhanced vehicle 
     fuel efficiency standards might not actually decrease future 
     total gasoline consumed in the U.S. due to the anticipated 
     continued increase in numbers of drivers and vehicles. Thus, 
     a new CAFE mandate might decrease the rate at which future 
     gasoline consumption increases, but not necessarily reduce 
     total consumption. Only aggressive vehicle fuel efficiency 
     standards legislation that ``pushes the envelope'' of fuel 
     efficiency technologies over the next two decades (as 
     determined, for example, in the study by the National 
     Research Council of the National Academy of Sciences is 
     likely to actually reduce total U.S. gasoline consumption.
       Savings in the U.S. Assuming a crisis atmosphere, we 
     hypothesize an aggressive vehicle fuel efficiency scenario, 
     based on the NRC CAFE report and other studies that estimate 
     the fuel efficiency gains possible from incremental 
     technologies available or likely to be available within the 
     next decade. We

[[Page 26535]]

     assume that legislation is enacted on the action date in each 
     scenario. We further assume that vehicle fuel efficiency 
     standards are increased 30 percent three years later--for 
     cars from 27.5 mpg to 35.75 mpg and for light trucks from 
     20.7 mpg to 26.9--and then increased to 50 percent above the 
     base eight years later--for cars from 27.5 mpg to 41.25 mpg 
     and for light trucks from 20.7 mpg to 31 mpg; finally, we 
     assume full implementation is assumed 12 years after the 
     legislation is enacted. These assumptions ``push the 
     envelope'' on the fuel efficiency gains possible from current 
     or impending technologies.
       On the basis of our assumptions, the U.S. would save 500 
     thousand barrels per day of liquid fuels 10 ten years after 
     legislation is enacted; 1.5 million barrels per day of liquid 
     fuels at year 15; and 3 million barrels per day of liquid 
     fuels at year 20.
       Worldwide Savings. The U.S. currently has about 25 percent 
     of total world vehicle registrations, but consumes nearly 40 
     percent of the liquid fuels used in transportation worldwide. 
     Since we could not find credible forecasts of the potential 
     impacts of increased worldwide vehicle fuel efficiency 
     standards, we assumed that the impact in the rest of the 
     world of enhanced vehicle fuel efficiency standards will be 
     about equal to that in the U.S. In total, the worldwide 
     impact of increased vehicle fuel efficiency standards would 
     thus yield a savings of 1 million barrels per day of liquid 
     fuels 10 years after legislation is enacted; 3 million 
     barrels per day 15 years after legislation is enacted; and 6 
     million barrels per day 20 years after legislation is 
     enacted.
       Increased vehicle fuel efficiency standards are a powerful 
     way to reduce liquid fuels consumption. However, they 
     required long lead-times to enact, implement, and become 
     effective in the past. On the other hand, their importance 
     and contributions continue to grow over time as older 
     vehicles are retired. We note that a detailed study of these 
     issues and opportunities would be of great value.


                            B. Coal Liquids

       High quality liquid fuels can be made from coal via direct 
     liquefaction or via gasification followed by Fisher-Tropsch 
     synthesis. A number of coal liquefaction plants were built 
     and operated during World War II, and the Sasol Company in 
     South Africa subsequently built a number of larger, more 
     modern gasification based facilities.
       While the first two Sasol coal liquids production plants 
     were built under normal business conditions, the Sasol Three 
     facility was designed and constructed on a crash basis in 
     response to the Iranian revolution of 1978-79. The project 
     was completed in just over three years after the decision to 
     proceed. Sasol Three was essentially a duplicate of Sasol Two 
     on the same site using a large cadre of experienced 
     personnel. Sasol Three was brought ``up to speed almost 
     immediately.''
       The Sasol Three example represents the lower bound on what 
     might be accomplished in a twenty-first century crash program 
     to build coal liquefaction plants. This is because the South 
     African government made a quick decision to replicate an 
     existing plant on an existing, coal mine-mouth site without 
     the delays associated with site selection, environmental 
     reviews, public comment periods, etc. In addition, 
     engineering and construction personnel were readily 
     available, and there were a number of manufacturers capable 
     of providing the required heavy process vessels, pumps, and 
     other auxiliary equipment. While we have not done a survey of 
     worldwide capabilities to perform similar tasks today, it is 
     our belief that such capabilities are now in much shorter 
     supply--a situation that will worsen dramatically with the 
     advent of a worldwide crash program to build alternate fuels 
     plants. We have therefore attempted to strike a balance 
     between what we believe could be a somewhat slow startup of a 
     worldwide coal liquefaction industry and a later speed up as 
     experience is gained and new plants are built as essentially 
     duplicates of previous plants.
       Our coal liquefaction wedge thus assumes that the first 
     coal liquefaction plants in a worldwide crash program would 
     begin operation four years after a decision to proceed. We 
     assume plant sizes of 100,000 bpd of finished, refined 
     product, and we assume that five such plants could be brought 
     into operation each year. We cannot predict where in the 
     world these coal liquefaction plants might be built. 
     Candidate countries with large coal reserves include the U.S. 
     and the Former Soviet Union with the largest, followed in 
     descending order by China, India and Australia. We note that 
     a consortium of Chinese companies has recently signed a 
     letter of intent with Sasol for feasibility studies on the 
     construction of two new coal-to-liquids plants in China.
       If U.S. siting and environmental reviews of new energy 
     facilities were to continue to be as time consuming as they 
     are today, few coal liquefaction plants would likely be built 
     in the U.S. On the other hand, China has been quick to 
     approve major new facilities, so coal liquefaction plants in 
     that country might well be built expeditiously and 
     economically. Because there is presently a large 
     international trade in coal, it is not inconceivable that 
     coal-poor countries might become the sites of many coal 
     liquefaction plants using imported coal, possibly even from 
     the U.S.


                        C. Heavy Oils/Oil Sands

       As noted, significant heavy oil production currently exists 
     in Canada and Venezuela. While their total resource is 
     estimated to be 3-4 trillion barrels, recoverable oil 
     reserves are estimated to be roughly 600 billion barrels. 
     Such reserves could support a massive expansion in production 
     of these unconventional oils.
       In the case of Canadian oil sands, a number of factors 
     would challenge a crash program expansion, such as the need 
     for massive supplies of auxiliary energy, huge land and water 
     requirements, environmental management, and the harsh climate 
     in the region. In the case of Venezuela, large amounts of 
     supplemental energy, inherently low well productivity and 
     other factors will likely pose significant challenges.
       We know of no comprehensive analysis of how fast the 
     Canadian and Venezuelan heavy oil production might be 
     accelerated in a world suddenly short of conventional oil. 
     Recent statements by the World Energy Council (WEC) guided 
     our wedge estimates:
       ``Unconventional oil is unlikely to fill the gap 
     (associated with conventional oil peaking). Although the 
     resource base is large and technological progress has been 
     able to bring costs down to competitive levels, the dynamics 
     do not suggest a rapid increase in supply but, rather, a 
     long, slow growth over several decades.''
       ``(Extrapolating expectations of TOTAL Oil Company in the 
     Orinoco, Venezuela) overall reserves today would be only 60 
     Gb over 30 years, allowing at best 6 MM bpd of production in 
     2030 if the entire area were put into production.''
       ``Current estimates put the additional production of Canada 
     (heavy oil) . . . at less than 2 MM bpd in 2015-2025.''
       In line with the WEC, we assume the following for our 
     Venezuelan Heavy Oils wedge:
       1. Accelerated production might begin three years after a 
     decision to proceed with a crash program. This delay is based 
     on the fact that the country already has significant 
     production underway. Starting from scratch would require much 
     more time.
       2. Under business-as-usual conditions assumed by the WEC, 
     Venezuela would have production of 6 MM bpd in 2030--5.5 MM 
     bpd beyond production of 0.5 MM bpd in 2003. If we assume 
     this level of production is achieved 10 years after 
     initiation of a crash program, rather than the roughly 25 
     years estimated by WEC, then roughly 5.5 MM bpd of 
     incremental production might be achieved 13 years from a 
     decision to accelerate.
       3. In contrast to the WEC, we assume that Venezuelan 
     production is not capped at 6 MM bpd but continues to expand 
     for the period covered by our approximations. Note: We ignore 
     the currently extremely unstable political environment in 
     Venezuela and assume that scale-up timing is not hindered by 
     local politics.
       Our assumptions for Canadian oil sands are as follows:
       1. Again, accelerated production might begin three years 
     after a decision to proceed with a crash program, based in 
     large part on the fact that the country already has 
     significant production underway.
       2. Current plans are for production of 3 MM bpd of 
     synthetic crude oil from which refined fuels can be produced 
     by 2030. This is above current production of 0.6 MM bpd. If 
     we assume this level of production is achieved 10 years after 
     initiation of a crash program, rather than the roughly 25 
     years targeted by the Canadians, then roughly 2.5 MM bpd of 
     incremental production might be achieved 13 years from a 
     decision to accelerate.
       3a. We know of no upper limit on Canadian oil sands 
     production, so for purposes of this order-of-magnitude 
     illustration, we do not assume one.


                        D. Enhanced Oil Recovery

       Because it is impossible to evaluate the worldwide impact 
     of Improved Oil Recovery (IOR) techniques, we can only 
     provide a rough estimate of what might be achieved. We focus 
     on a major subset of IOR technologies--Enhanced Oil Recovery 
     (EOR). While EOR can add significantly to reserves, it is 
     normally not applied to a conventional oil reservoir until 
     after production has peaked. As discussed earlier, the most 
     widely applicable EOR process involves the injection of 
     CO2 into conventional oil reservoirs to dissolve 
     and move residual oil. Because EOR processes require 
     extensive planning, large capital expenditures, procurement 
     of very large volumes of CO2, and major equipment 
     for large reservoirs, our simplified assumptions parallel 
     those for our heavy oil and coal liquids wedges.
       We assume that the massive application of EOR worldwide 
     will not begin to show production enhancement until 5 years 
     after the peaking of world oil production, paced primarily by 
     the difficulties of procuring CO2. We further 
     assume that world oil production enhancement due to such a 
     crash effort worldwide will increase world oil production by 
     roughly 3 percent after 10 years. We translate the 3 percent 
     to 3 MM bpd, based on our assumed world oil peaking level of 
     roughly 100 MM bpd.


                           E. Gas-To-Liquids

       Estimating how fast world Gas-To-Liquids (GTL) production 
     might grow as a result of the peaking of world oil production 
     is an extremely complex undertaking because of the

[[Page 26536]]

     need to consider the total world energy system, its likely 
     growth by country, future energy economics, other resources 
     that compete with natural gas, etc. In a crash program, GTL 
     plants might be built in a number of counties that have large 
     reserves of stranded gas. Once operational, GTL product could 
     be moved to markets around the world by conventional oil 
     product tankers.
       Our estimates for a crash program of world GTL production 
     are tempered by the conflicting world demand for Liquefied 
     Natural Gas (LNG), whose export volumes are currently growing 
     at a rapid pace. The tradeoffs involved in estimating the 
     future LNG/GTL balance are complex, and a world crash program 
     in GTL could yield higher or lower volumes than our 
     estimates. Note also that seven countries currently account 
     for almost 80 percent of the world gas export market, and it 
     is not inconceivable that the recently formed Gas Exporting 
     Countries Forum (GECF) might well evolve into a future OPEC-
     like cartel.
       Again, we assume a startup delay of three years before 
     crash program GTL plants might come into operation. Using a 
     base case, business-as-usual production forecast of 1.0 MM 
     bpd in 2015 from the current level of essentially zero, we 
     assume that a crash program might yield the 1.0 MM bpd in 5 
     years.


                          F. Sum of the Wedges

       A summary of the estimates from the foregoing is presented 
     in Table A-2.

    TABLE A-2.--SUMMARY OF CONSUMPTION AND PRODUCTION WEDGE ESTIMATES
------------------------------------------------------------------------
                                          Delay until
               Category                   first impact   Impact 10 years
                                            (years)       later (MM bpd)
------------------------------------------------------------------------
Vehicle Efficiency....................               3                3
Gas-To-Liquids........................               3                2
heavy Oils/Oil Sands..................               3                8
Coal Liquids..........................               4                5
Enhanced Oil Recovery.................               5                3
------------------------------------------------------------------------

               Appendix V. Notes on Shale Oil and Biomass


                  A. Oil Shale by Gilbert McGurl, NETL

       Worldwide resources of oil shale comprise an estimated 2.6 
     trillion barrels, of which two trillion are located within 
     the United States. The richest deposits, 1.5 trillion bbl 
     with high concentrations of kerogen, lie in Colorado, Utah, 
     and Wyoming. An additional 16 billion barrels of rich but 
     physically different oil shale is found in Kentucky, Indiana, 
     and Ohio. A recent estimate is that, from the Green River 
     deposits, 130 billion barrels of oil may be produced. 
     Technology development on oil shale `retorting' reached a 
     high point in the late 1970s, with the major oil companies 
     leading the way. The oil price collapse of the 1980s, the 
     dissolution of the synfuels program, and the termination of 
     the Unocal project in 1991 led to the demise of oil shale 
     production in the United States.
       A recent study performed by the DOE Office of Naval 
     Petroleum and Oil Shale Reserves advocates a research and 
     development program with a production goal of two million 
     barrels per day by 2020. Production would be initiated by 
     2011. Traditional technologies for mining and preparation of 
     oil shale ores and for aboveground upgrading have been 
     `proven' at less-than-commercial scale. Newer Canadian 
     technologies have been tested at demonstration projects in 
     Australia. However, that project, the Stuart upgrading 
     project, is currently suspended pending project re-design. 
     Nonetheless, the same technology has been licensed by 
     operators in Estonia. Technologies for in-situ recovery are 
     newer and less developed. In 2000, Shell revived an oil shale 
     project called ``Mahogany'' in Colorado. Shell aims to test 
     its process until 2010. If successful, the in-situ method 
     would leave heavier hydrocarbons in the shale while producing 
     lighter hydrocarbons and using much less water than 
     traditional methods.
       Most Estonian processing of oil shale has been for boiler 
     fuel for electricity production. Small liquids facilities 
     have been operating at ``full capacity'' given recent market 
     oil prices. There are no solid figures for cost in large-
     scale plants since none have been built. The aborted 
     Australian project estimated $8.50/bbl in operating costs 
     once a commercial plant had been built. The Estonians 
     estimate a break-even point at $21 Brent price (app $23 WTI) 
     and low capacity factor. At higher capacity factors, plants 
     may operate profitably even with prices in the mid-teens.
       Besides water use and production, environmental concerns 
     include fine particulates and carbon dioxide emissions. Since 
     the last US oil shale project ceased operation before the 
     implementation of the 1990 Clean Air Act amendments, new 
     emission-control equipment would need to be tested on US 
     shales.


                   B. Biofuels by Peter Balash, NETL

       Bioethanol is produced as a transportation fuel largely in 
     only two countries. In 2003 the US produced about 2.8 billion 
     gallons and Brazil produced 3.5 billion gallons. All of this 
     ethanol is produced by conversion of starch to sugar and 
     fermentation to ethanol. In the US ethanol represents about 
     1.4% of the BTU content (2.0% by volume) of gasoline used in 
     transportation. Current costs for ethanol production in the 
     US are said to be $0.90 per gallon, which is equivalent to a 
     gasoline price of $1.35 per gallon. Because of recent 
     increases in energy costs current costs will be somewhat 
     higher. Grain ethanol provides only a modest net energy gain 
     because of the energy required to produce it. USDA calculated 
     a net energy gain of 34% for a modern corn to ethanol plant, 
     but there is considerable controversy over the real 
     efficiency of the process. Most of the energy used to produce 
     ethanol comes from natural gas and electricity. The 
     production of ethanol uses only about 5% of the corn crop in 
     the US. Significant expansion is possible but at some point 
     there might be an impact on food prices.
       Cellulosic ethanol is currently being produced only in two 
     rather small pilot plants but is capable of producing about 
     40% conversion of cellulosic biomass to ethanol while 
     providing all the energy needed for the process and exporting 
     a modest amount of energy as electricity. It is anticipated 
     that successful research may reduce the cost of cellulosic 
     ethanol to about $1.10 per gallon by 2010. If this occurs the 
     potential ethanol to mitigate peaking is high. Using only 
     waste biomass and grass grown on land currently in the 
     conservation reserve could produce 50 billion gallons of 
     ethanol which would be equivalent to 35 billion gallons of 
     gasoline or 17% of current US consumption. This could be 
     achieved without any impact on current food production and at 
     prices only $0.35 per gallon higher than refinery prices for 
     gasoline. Since ethanol has an RON of 130 and a MON of 96 it 
     raises the octane of the gasoline to which it is added and 
     has a premium value as a result.

                  Appendix VI: Areas for Further Study


    1. Economic Benefits to the U.S. Associated With an Aggressive 
                         Mitigation Initiative

       Important economic and jobs benefits could result from a 
     concerted U.S. effort to develop substitute fuels plants 
     based on U.S. coal and shale resources and scale up of EOR. 
     The impacts might include hundreds of billions of dollars of 
     investment, hundreds of thousands of jobs, a rejuvenation of 
     various domestic industries, and increased tax revenues for 
     the Federal, state, and local governments. The identification 
     and analysis of such benefits require analysis.
       In the short run, the U.S. would be hard-pressed to find 
     adequate physical and human resources to plan, develop, 
     construct, and operate the required facilities. Given that 
     oil peaking is a world problem, it is virtually certain that 
     at the same time the U.S. embarked on an aggressive 
     mitigation program, other major initiatives would likely be 
     undertaken elsewhere in the world. All would require similar 
     types of capital, technology, and human resources, generating 
     additional constraints and inflationary pressures on the U.S. 
     program. Assessment of the impacts of these constraints on 
     the feasibility, costs, and timing of a major U.S. mitigation 
     program merits investigation.


   2. Oil Peaking Risk Analysis: Cost of Premature Mitigation versus 
                                Waiting

       The date of world oil production peaking is unknowable, but 
     it may occur in the not too distant future. Large-scale 
     mitigation is needed more than a decade before the onset of 
     peaking if economic hardship is to be avoided. If major 
     efforts were initiated early and peaking was to occur decades 
     later, there might be an unproductive use of resources. On 
     the other hand, mitigation initiated at the time of peaking 
     will not spare the world from a decade or more of devastating 
     economic impacts. A careful analysis of the benefits/costs of 
     early versus late mitigation could provide valuable insights.


  3. U.S. Natural Gas Production as a Paradigm for Viewing World Oil 
                                Peaking

       The history of U.S. natural gas production is cited as an 
     example of the perils of over-optimistic resource forecasts. 
     A detailed analysis of the North American natural gas 
     history, status, and outlook might provide lessons useful in 
     addressing world oil production peaking.


         4. Potential for Non-transportation Oil Fuel-Switching

       World non-transportation liquid fuel usage is amenable to 
     fuel switching, thereby freeing up liquids for 
     transportation. If switching were to occur on a large-scale, 
     it would likely take place gradually because other energy 
     substitutes would have to be scaled up to meet the new 
     demands associated with a major shift, e.g., electric power 
     plants built, refineries expanded to produce a different 
     product slate, etc. A detailed study would provide an 
     understanding of how difficult, expensive, time-consuming and 
     productive worldwide non-transportation fuel switching might 
     be.


                   5. World Coal-To-Liquids Potential

       Sasol has operational coal-to-liquids (CTL) production 
     plants and is under contract to study the construction of 
     similar facilities in China. An analysis of worldwide large-
     scale CTL potential could yield a useful estimate of 
     complexity, timing and potential.


                 6. World Heavy Oil/Oil Sands Potential

       Canada, Venezuela, and, to a lesser degree, other countries 
     have potential to massively scale up their unconventional oil 
     production. A better understanding of how quickly scale-up 
     might be implemented, the related barriers, and ultimate 
     potential would help in the understanding the potential 
     contribution of these resources.

[[Page 26537]]




                         7. World EOR Potential

       An analysis of worldwide large-scale EOR potential could 
     provide an estimate of complexity, timing and potential.


                         8. World GTL Potential

       An analysis of worldwide large-scale GTL potential could 
     yield a useful estimate of complexity, timing and potential. 
     In particular, the likely conflicts between GTL and LNG 
     production could provide a quantitative estimate of likely 
     future use of world stranded gas.


     9. World Transportation Fuel Efficiency Improvement Potential

       It is important that we have the best possible 
     understanding of the U.S. and worldwide potential for the 
     upgrading of transportation fuel efficiency, including 
     possible timing, cost, and savings as a function of time. 
     Excellent data is available on U.S. transportation fleets, 
     but fleets elsewhere in the world are less well described. A 
     careful study is needed.


     10. Impacts of Oil Prices and Technology on U.S. Lower 48 Oil 
                               Production

       Analysis of U.S. Lower 48 oil production since the 1970 
     peak strongly suggests that oil prices and advancing 
     technology had little impact on the production decline. 
     However, a number of institutional factors also impacted 
     Lower 48 oil production, e.g., allowables (Texas Railroad 
     Commission), price and allocation controls (1970s), free 
     market pricing (since 1981), foreign opportunities for multi-
     national oil companies, etc. An in-depth understanding of 
     these various influences might provide useful guidance for 
     the future.


            11. Technological Options for Coal Liquefaction

       Current world coal liquefaction R & D is focused on 
     gasification of coal followed by the Fischer-Tropsch 
     synthesis. Other coal-to-liquids processes have been 
     proposed, some of which were tested at relatively large 
     scale. It may be worthwhile to revisit the various options in 
     light of today's technology and environmental requirements to 
     determine if any of them might also have competitive 
     potential.


          12. Performance of Oil Provinces Outside of the U.S.

       There is a strong rationale for using U.S Lower 48 oil 
     production as a surrogate pattern for future world oil 
     production peaking and decline. Other large oil province 
     histories could also yield valuable insights and alternate 
     patterns. Related analysis might provide an improved basis 
     for modeling future world oil production.


  13. How the U.S. Could Again Become the World's Largest Oil Producer

       After the peaking of world conventional oil production, 
     there will be a major world transition from the current world 
     liquid fuel infrastructure. Over time, major conservation and 
     energy switching initiatives will almost certainly be 
     implemented, but the need for liquid fuels will not disappear 
     for at least the remainder of this century because there are 
     no known alternatives for a number of transportation 
     applications. An analysis of the major factors required for 
     the U.S. to return to a position of oil supremacy and oil 
     independence would be enlightening.


                14. Market Signals in Advance of Peaking

       Increases in oil prices and oil price volatility have been 
     identified as two precursors of world oil peaking, but both 
     are likely short-term signals. The identification and 
     character of longer-term signals, if they exist, could be of 
     significant value.


15. Risk of Repeating the Synthetic Fuels Experience of 1970s and 1980s

       One risk of embarking on aggressive oil peaking mitigation 
     is that OPEC might undermine such efforts by dramatically 
     increasing conventional oil production. This could only 
     happen if excess capacity were to exist, which could happen 
     if world oil peaking was many decades away. Were such a 
     dramatic increase in OPEC production to occur, governments 
     would be under pressure to terminate support for their 
     mitigation programs. Related scenarios might worthy of study.


       16. Effects of Oil Price Spikes in Causing U.S. Recessions

       Oil price spike have been followed by U.S. recessions, but 
     they are not the only cause of recessions. A detailed study 
     of the role of oil prices and other factors in causing 
     recessions might be worth further study.

                          ____________________