Delivered on March 8, 2007
I'm pleased to be invited to The Heritage Foundation and to
develop with Heritage and in Washington what might be called the
"shale story," which currently is almost silent with regard to
national policy and world petroleum. Earlier on, I edited a book on
the resource war in the Reagan Administration. It was based upon
how to understand, how to conceptualize strategic resources: oil,
gas, and hard-rock minerals. I'm currently based both on the East
Coast and in New Mexico, participating in the New Mexico energy
model for the country and maybe the world.
The New Mexico model is based on a diversity of fuels. It is not
exclusive; in fact, the language of "alternative," "conventional,"
"bio," "geo" is almost disappearing. The concern statewide is: What
is fuel? Where is the supply of energy going to come from? And the
model is diversification, which in New Mexico means solar; the
energy technology of national laboratories; the fourth largest
producer of natural gas (California depends on New Mexico for 30
percent of its gas and electricity); the potential for hydrogen;
the utilization export of CO2; and, finally, oil.
That's an effective energy production model for the country to
follow. In one portfolio, all the energy assets are recognized
systemically rather than competitively in terms of production of
energy and fuels. Robert Gallagher, who served in Washington in the
Clinton Administration Department of Energy (DOE) and is now
president of the New Mexico Oil and Gas Association, has made the
New Mexico model an operational success.
Shale is a very big part of American history. First of all,
shale is not "yesterday" in the sense of the current crisis of
energy security. It goes back to 1913, to Winston Churchill, to the
British establishing a state company entering Persia to secure the
access to petroleum for the Navy, and, in a parallel action, the
United States establishing the Office of Naval Petroleum and Oil
Shale Reserves (its current designation in the Department of
Energy). From 1913 on, government and industry have been watching
these oil shale reserves.
Oil shale has an episodic history that relentlessly provokes
frustration. Why is it not developed? It even produced histories
and congressional hearings in the 1960s and 1970s of almost
novel-like proportions. The most interesting point is that the
pioneers, with covered wagons, knew about shale. They found it
going west in the 19th century and used it for axle grease in their
wagon wheels. So the petroleum-like end-use of shale oil took place
before the country was unified coast to coast.
While the government established this office, geologists of the
time established that in the Rocky Mountain region, in three
petroleum basins-the Piceance Basin is one-there was an enormous
oil reserve which was locked into shale rock in the form of what is
called kerogen. Kerogen is an obscure pre-petroleum organic
sediment. It is what nature did not complete by heat and
combustion, the process that developed petroleum. There was
insufficient heat to transform the molecules in this material into
petroleum, so it remains in the pores of enormous shale rock
formations in northwest Colorado, Wyoming, and some in Utah, all
far from the Persian Gulf.
This oil shale set Congress on its heels. The Mineral Leasing
Act of 1920 was changed to promote oil shale development in the
United States, because 1920 was a scarce period. We were running
out of oil, very similar to some scenarios of the last two years.
And then nothing happened; the potential of oil shale went silent.
Under President Herbert Hoover, the decision was made to abandon
leasing of oil shale. Fifty-four years passed without one lease
going into shale.
The Second World War stimulated official interest. The U.S.
Bureau of Mines, since abolished, began research on oil shale.
Stewart Udall, who was a founder within the Democratic Party of
the environmental movement, was pro-shale. As Secretary of the
Interior, he mobilized in the 1960s to move shale forward, to lease
it, to make it commercial, but this effort failed again. The debate
over oil shale in the 1960s concluded that the very low price of
conventional petroleum ruled out shale. Required oil shale
investment could not compete against imported, low-cost petroleum
as American companies went worldwide in the '60s. At that point,
the economics were not favorable.
In the 1970s, with the OPEC embargo and the price escalation,
shale once again attracted attention, and the first leases went
forward. American oil companies applied for leases and paid $41,000
per acre in Colorado. Seventy-five percent of the shale is federal;
25 percent is patented private.
How large is this resource? In the Piceance Basin, an area of
1,100 square miles, the oil shale is over 1 million barrels per
acre, or roughly 750 billion barrels of recoverable oil. If you
extend outward to Wyoming and to Utah, it is 1.3 trillion. This is
why you hear shale next to trillions, not billions or millions, of
barrels. The Air Force in the 1970s looked at shale, tested it, and
found that it was a superior liquid for jet fuel. Roughly 65
percent of the oil shale is liquid, which could go into jet fuel.
The J-8 engine can take shale oil as premium jet fuel.
These are the dynamics now. From the 1970s, in which the Iranian
hostage events and consequent escalation in price led to the 1980s
Synfuels Corporation and its abandonment, a good deal of government
incentive and private initiative advanced oil shale technology and
pilot scale production. Why did it fail in 1982? Look at the price
charts. Saudi Arabian exported production expanded, and new
supplies, non-OPEC and OPEC, came on the market. The market was
saturated with conventional oil from the Middle East, and prices
fell rather radically to about $15 a barrel, which was less than
break-even for Texas oil in 1986. So the market again changed the
dynamic against shale oil.
Apart from supply and demand, there is the technology variable.
The oil shale technology of the 1970s is not the technology of
2007. The technology of the 1970s had imposed a surface disturbance
footprint which today would be unacceptable in the United States.
The process to recover kerogen and upgrade it was essentially
mining; that is, to take the shale itself, ton by ton, to the
surface and to crush it with great volumes of water and retort it,
creating spent shale or tailings for disposal. Then there were
extraordinary water requirements: over three barrels of water for
one barrel of shale.
What has changed since the 1980s are the dynamics of supply,
demand, security, and technology. Two years ago, a major superstorm
struck the Gulf of Mexico, which supplies 30 percent of our oil and
25 percent of our natural gas. We are increasingly concentrated in
the Gulf of Mexico. Congress was unable under the Republican
majority to pass Outer Continental Shelf legislation, which would
have expanded access to oil and gas offshore. With one minor
concession in the Gulf, nothing was done. We are still dependent on
a Gulf-centered domestic supply.
Second, what happened with Katrina was that it triggered
thinking about natural disaster and its relation to climate change,
because the climate change movement saw the storm as the function
of superheated oceans, which would cause more superstorms. This
caused another development in the market itself. All of the oil and
gas, heating oil, and related products' prices are determined in
futures markets on a 24-hour basis from Singapore to New York. Both
investors and speculators began to see that there was a new
vulnerability to oil supply, not only caused by the war in Iraq and
the geopolitics of the Middle East, but also from natural disaster
linked to global warming. They began unprecedented speculation in
oil, driving the price up to the historic high of late last
The interesting part of that was the belief of speculators in
the forecasts of climatologists, who study climate change, that
there would be seven superstorms last summer of the Katrina class.
But none occurred, and gradually the prices of oil fell from the
high of $78 per barrel to the low of $50, and now we're in the
middle range. This shows some uncertainty and unpredictability
about those climate change scenarios.
Shale oil is not responsible for price or technology; the
resource is simply in place. Resource recovery is feasible. Around
it is a technology change, and around that is always price. Why
that Colorado shale hasn't been on the market, and where we would
be today if it had been, is a function outside the resource itself
and the technology used to make it into oil. It is a function of
policy and price.
There is a silence about this that I want to call your attention
to. Those of you who are familiar with the Energy Policy Act of
2005 can turn to Section 369, which calls upon the Administration,
the DOE, to produce a report to make policy recommendations to
commercialize oil shale in the United States and to recognize it as
a strategic fuel. That report was mandated by Congress, but it has
not yet been released and sent to Congress. It contains incentives
that are needed still to develop the shale in Colorado. Those
incentives are quite obvious.
There is a market risk in shale, as I pointed out, because of
the oil price volatility over the last 87 years and the episodic
way shale has been handled by the world market and government.
Market risk reduction is among the DOE recommendations, and that
translates into production tax credits and possibly one other item
which I'm going to mention: streamlining the permitting process. Go
to the Energy Policy Act; you'll see in Section 369 what was
mandated about shale and perhaps why it is has not been
The Energy Policy Act of 2005 created a partnership with Alberta
in tar sands development. Alberta is the world's largest producer
of tar sands or bitumen, another unconventional
fuel source, which could reach 4 million barrels of oil
per day by 2012. Alberta's fuel exports to the United
States are greater than Saudi Arabia's. It has been a success
story. The conversion of tar sands through natural gas and steam
injection has produced oil, and those reserves in Alberta are now
classified officially as reserves, not resources. That exists in
U.S. legislation, in law, to form those partnerships.
So as President Bush leaves Washington this afternoon to go to
Brazil to sign a well-publicized agreement on Brazil's sugar
conversion to ethanol, why not add to that an agreement under
Section 369 of the Energy Policy Act 2005: an agreement with the
Brazilians to co-develop, share technology and information on,
Brazilian oil shale? The United States has 1.3 trillion barrels of
reserves, followed by Brazil with 90 billion barrels. With 90
billion barrels of new oil reserves in Brazil, the geopolitics of
Latin America oil will surely change.
Why am I optimistic about shale in 2007? It's been 25 years
since the world petroleum price shut down development in Colorado.
What is now available in terms of technology that changes the
perspective of shale? Why should we not call shale an official
strategic fuel in the United States, and why not commercially
develop it in a most aggressive way?
The technology issue is moving significantly in terms of
progress. For example, one major development is the Shell Oil
project in Colorado. Shell has established some leadership; it has
been in Colorado for 30 years. It has invested, in terms of
research and development, a significant amount of its own revenues
and is moving toward commercialization.
Shell has Bureau of Land Management research and development
leases and is moving stage by stage to prove up and resolve all the
issues around extraction of shale through a proprietary process
called the in-situ conversion process. Understanding ICP requires a
visualization that eliminates the surface retort heating and
disposal of shale rock as a mining-industrial process. Shell is
going underground. The refinery of shale will be underground, with
almost no surface impact. This is a breakthrough change in
technological capability, and it makes shale accessible. Shell is
confident that it can recover shale oil with the price of West
Texas intermediate oil at around $25 a barrel.
Older studies have always argued-again, using the 1970s know-how
and data-that surface processing would create prohibitive costs
extending to intractable problems of reclamation; and water use in
the older studies, as I said, was projected at three barrels of
water to one barrel of oil shale oil. However, Shell is going
underground into the shale formation with electrical heaters. The
heaters will provide high-temperature radiant heat, which will then
do what nature did not do for organic matter when it was
transformed into conventional petroleum. The shale rock under very
hot conditions and combustion will yield kerogen, which will flow
to the surface through production wells.
There is silence about shale in Washington, but not among the
bloggers. I read the bloggers, and many of them have discovered
shale. Many of the bloggers out in the West have a nightly debate
What you see here is a potential for an environmentally friendly
extraction of shale for the first time: no surface problems,
nothing on the surface, an underground refinery. That is a change
not available in 1981. But it has to be done by way of creating
from Shell's conception, under today's social and environmental
standards, protection of water. So Shell is developing the
technology of an ice wall around the action of heating the shale,
and the ice wall that they're going to put up-they're doing it
experimentally now-must contain liquids from going into groundwater
and protect the thermal process from water intrusion.
Los Alamosjoined the shale development technology just three
months ago and signed an agreement with Chevron. Chevron is going
to use another unique technology; it is going to approach the rock
itself, rubbleize it by explosives, and then flush the kerogen out
with a critical liquid, which is CO2. CO2 is
utilized as another method to reduce greenhouse gases or global
The bottom line here is that the approach to shale extraction
and converting it into oil in the United States will be a
technology that will contain carbon. There will be a carbon
footprint that will be established to diminish the carbon emission
from the process of production by way of sequestering carbon,
storing it underground, putting it into saline aquifers, and so on.
Is there any basis for the claim that the conflict between shale
oil and the environmental or climate change crisis is
irreconcilable? Nothing will move forward without a carbon
footprint integrated in the technology of recovery.
The resource, again, is in the trillions of barrels of oil, and
if you compare, Saudi Arabia's official reserves are about 289
billion barrels. The New York Times said last week that it
had discovered what is called essentially unconventional fuel,
which is the topic today, and the petroleum industry is looking at
how to get more oil out of existing fields. The Saudi response to
that was, "We too can do that; we can potentially double our
reserves, albeit with extraordinary investment."
If the Saudis upgraded their own recovery technology, which
would take billions to do, they would still have one-half of the
reserves in oil shale discovered in Colorado. We're talking still
about 1.2 trillion, 1.3 trillion barrels of oil; the Rocky Mountain
region is the Saudi Arabia of oil shale. The United States has 75
percent of the world resource, which is about 1.8 trillion barrels.
Brazil is next.
As the size of the resource grows, you can see the geopolitical
configuration follows. China has announced government incentives
for shale development in the last six weeks, while Washington is
silent on Section 369. Then there is a series of interesting
countries in the Middle East without conventional oil: Morocco,
Israel, and Jordan are the next shale reserve holders in the world.
This is a configuration of potential shale producers that might
have an international organization, an OPEC of shale one day, and
transfer of the technology. I should add Estonia, which develops
much of its energy from oil shale.
Where are we with regard to the market today and investment? The
price of oil will continue as the uncertain variable, and that's
why the recommendations are still to look at shale and market risk
Secondly, there is the permitting process. Shale was once seen
in the United States as so valuable that anti-monopoly issues
dominated government shale policy. The government decided at one
point that it wanted competition in shale and limited the acreage
to 5,000 acres per company. We changed that in 2005 to 25,000 in
five different locations; but if you look at the acreage per
resource, 1 million barrels of oil from oil shale per acre, you'll
get the idea of what acreage does. Do your computation: Bureau of
Land Management R&D leases are 160 acres each. Underneath an
R&D lease, there are roughly around 250 million barrels of oil,
or over five months of Saudi Arabian spare capacity needed to
stabilize the world market.
How long can oil shale last? There is enough shale to sustain
United States consumption of crude oil easily through 2120. One of
the arguments in the energy security debate has been foreign oil
import dependence. Some elements of the national security community
in Washington have joined the alternative fuels community, the
biofuels community, under the notion that we are dependent upon
potentially hostile supply sources after 9/11, which could be
disrupted or politically manipulated.
The national security argument, or the energy security argument,
centers on foreign oil import dependency. If shale is
commercialized by 2012, we can, under production from Colorado
alone, eliminate dependency on Middle East oil by 2020. The
President wants to lower it by 20 percent by 2017.
Shale production will eliminate it altogether, and that
dependence is roughly 2.3 million barrels a day. The projection is
that when it is commercialized, with the ramp-up that will occur,
and with everything favorable-that is, world price-we would be at 2
million barrels a day, or the objective of the Department of Energy
in the shale process. Currently, we're getting 2.2 million barrels
a day from the entire Middle East: 19 percent of our total
Our major sources of imports are Canada and Mexico-that is,
North America-and oil shale would expand a North American domestic
energy source, which minimizes and reduces foreign oil dependency
with GDP benefits to the American people. Some of the projections
are that when shale is commercialized in the next three to five
years, the market price will decrease at least $5 a barrel. That's
conservative, but that depends on supply and demand worldwide and
the growth of economies worldwide.
There's been a great deal of excitement about biofuels, and as
you know, in Mexico and New Mexico and Arizona, the prime base for
a staple tortilla is white corn. Because of the biofuels
investment, U.S. farmers are beginning to turn their crops from
food to fuel, and white corn has almost disappeared from the
market. Even though Mexico has a NAFTA quota of 460,000 tons a
year, Mexico is not getting it, so the price of tortilla corn in
Mexico has had people demonstrating in the street and has caused
low-income families difficulties in buying daily bread. I introduce
that in contrast to the notion that we have a resource that has no
impact whatsoever on food supply.
I'll conclude with a point about the history of this. When you
leave here, the question is, Why is there silence today, in this
Administration, on shale? There is a strategic task force that for
two years has been meeting with five governors, and they have
recommendations. There are two major companies with leases moving
through R&D incrementally. A week ago, Shell had community
discussions to bring in 600 employees into the shale area in the
Rocky Mountain slopes.
That's big news; that's jobs and so forth. The perception is
that something is going to happen, and something rather big. But
there is a gap between the technology, the availability of the
resource, the commercialization that is coming, and Washington
Probably the most effective signal, apart from releasing the DOE
report, derives from the President's proposal in the State of the
Union to add 750 million barrels of oil to the Strategic Petroleum
Reserve by the year 2020. I would propose a long-term contract with
shale oil producers, that all of the production from 2013 in shale
oil from Colorado and the Rocky Mountains to 2020 be dedicated to
the SPR. Under existing law-again, the Energy Policy Act of
2005-the U.S. government can enter into long-term purchase
agreements and buy oil from shale for the SPR. That would be an
internal oil supply; it eliminates the national security risk of
foreign oil import beneficiaries.
This would be a powerful incentive for the oil shale industry.
It would itself reduce market risk without subsidies to a
phenomenally low level, and it would put the U.S. government in the
forefront of assuring energy security. The Department of Defense
could also be a buyer of jet fuel, along with the SPR, and this
would accelerate rapid commercialization.
So if the intention is to add to the Strategic Petroleum Reserve
to improve energy security, then buy into strategic, unconventional
fuel produced in the United States. That would mitigate historic
market risk a century after discovery.
There are some who say that 1.3 trillion barrels, under market
and positive circumstances, could eventually be ramped up to 10
million barrels a day. With a resource like that, at 10 million
barrels a day, we are moving back to the 1960s, close to a position
where our import dependence on petroleum is becoming marginal.
Using that number-and that is a remote number, far off, but
absolutely doable under the resource that exists and the
technology-that would give us the following composition: We would
be 80 percent North American at that point, with Mexico, Canada,
Colorado, the oil shale, and conventional Texas, Alaska, all
factored in, and maybe 20 percent oil dependent.
Borcherd & Company. I'm currently working in Alberta with the
Canadians on the water problem. The water problem is one of the
biggest problems because it takes anywhere from two gallons to four
gallons to produce one gallon of petroleum. It has a terrible
effect on the natural environment, and many problems are coming
from that. Do you have any comments on that particular problem?
Fine:It's quite true. The retort that I talked about,
building your processing and wetting the shale-that was where the
water went-was about three to one. This is also cited in the RAND
report, which was mildly negative on oil shale. But it is a
dimension of the problem that existed in 1979. The two processes
that I've mentioned, the injection of the supercritical fluid,
which flushes the kerogen out of the rock and so on, is
CO2, and that is recycled. That becomes the problem
today: the carbon footprint, how to get that manageable.
Neither the Chevron nor the Shell process is going to be
water-excessive; and they have to be sensitive to the Colorado
River Basin, because that is the source of the water, and share the
water under 21st century standards. So I believe that the water
problem is less under technology change than it was. What has
changed is the fact that you've got a carbon-based material, and
you have to capture the carbon to CO2, use it, inject
it, store it, and that's what's going forward under the Bureau of
Land Management leases today. So it's no surprise that the carbon
footprint is integrated in shale development; it's not hostile to
Couchman with Sunoco. If you look at a map of where the pipelines
that run crude oil in the U.S. are and where the refineries in the
U.S. are, middle-American refineries-that is, Ohio, Texas,
Oklahoma-the middle part of the country has access to crude
pipelines running pretty much from anywhere to anywhere. If you
look at the coasts, California and the East Coast-particularly the
Philadelphia region-they don't have crude pipelines that run to
So when this oil shale is developed to the point where it's very
commercially available, getting it to a significant portion of
domestic refining capacity is going to be a bit of a problem. Are
there any policies that you would recommend to change the current
ability to site crude pipelines to overcome state and local
opposition, which currently handle the regulations?
Fine:There are current pipelines in the Piceance Basin,
Rio Blanco County, running to Salt Lake; Salt Lake is pipeline
connected. The infrastructure was put in place and refining and
upgrading again in Salt Lake. It has a regional component.
What I would do is look at a very interesting development. The
Canadians face a pipeline problem as well, and a refining problem
with their tar sands in Alberta. So a leading Canadian company and
ConocoPhillips decided to reinvest, or invest in each other. Conoco
Phillips will make its refineries in the lower 48 open to tar sands
product, bitumen, coming through. That's the twin of kerogen coming
out of the tar sands. So the tar sands from Alberta will go to two
or three mid-U.S. refineries. This is the adaptability on the
refinery issue to get both tar sands and oil shale to market, to
refine and get it into the system as well.
It has not become a problem in terms of development; the
obstruction to development is not transportation at this point.
Utah has some tar sands and some shale, and they will have to
connect Utah into the pipeline infrastructure. It might be a little
different. Utah has about 12 billion barrels of oil shale against
the Colorado, and Wyoming is another player in that.
If you want a measurement, per ton of rock in Colorado, 35
gallons of oil, roughly, and then it declines in Wyoming to 20, 25
gallons; so Wyoming is less economic than Colorado. So visualize a
ton of rock, because this is unorthodox in terms of petroleum, and
what the rock will yield in terms of gallons. It is economic at 25
for one ton; that is now economic at $20 to $25 cost.
You all know the geopolitical issues in a world where the
national oil companies are changing contracts,
expropriating-Caracas, Venezuela-and diminishing the exploration
space for the same companies who are in Colorado: Shell, Chevron,
and so forth. It becomes almost an irrational resource question:
Why is a resource in the United States not developed, and why is
there so much silence around it?
you say is your answer to that? Why, in your opinion, is there so
much silence, and why is the resource so underdeveloped?
Fine:The reason for this is historic, in a way:
uncertainty over price. That's why I recommend the SPR as the
market-maker or initial buyer. Since the President declared, "We're
going to buy the oil," the next step is where are we going to buy
it? If it is purchased from oil shale in the Rocky Mountains, this
is an indirect way to assist an oil shale industry.
The second reason is the episodic way shale is handled. When The
Heritage Foundation said, "What is the best way to present this
lecture?" I answered "Back to the Future," because generations of
geologists and petroleum engineers, as students in mining schools
in the West, were exposed to a pyramid. At the top was conventional
oil, petroleum, from Texas. At the base of the pyramid was the
hard-to-get stuff. Shale was almost at the bottom, and underneath
shale were gas hydrates, which are even more difficult to get.
This was the American perspective from 1913 onward. My point is
the expectation that the hydrocarbon cycle could be deferred even
in the current crisis of energy security by a third element, apart
from economics and technology: namely, public policy distorted by
the public and the media reacting to agendas of security and
fear-and, of course, by climate change.
The issue on climate change is simple. The Congress debated it
for 18 months, and I watched all the debates from one side and the
other. A speaker from one faction or the other would say, "We've
got to reduce our dependence on foreign oil." The next speaker
would say merely "oil." Do we mean dependence on foreign oil or
imported oil, or dependence on oil itself?
If you look at it that way, there are two camps. Oil itself is
available and abundant: 3.7 trillion barrels in unconventional oil
in the world. There is the peak oil thesis, but the peaking out
means that your oil-finding level is lower than it has been. You're
not replacing as much as you did, in conventional oil only. But
"peak oil" simply means that the old pyramid comes into play; you
move down the pyramid, and the peak is rolled forward. You're on
plateau, and then you're into unconventional hydrocarbons oil.
Those who say the issue is oil itself make themselves very
clear: They want to move away from oil and all forms of carbon.
They want a carbon-free world, and that is their position. But
let's not confuse import dependency with that issue. Imported oil
does not equate with oil itself.
Hershey. I'm a consulting engineer. What do we have to learn from
the oil shale experience of Estonia?
Fine:Estonia has derived and continues to develop oil
shale for electrical power. It burns the shale. It can make a fuel
as well, but shale is around for production into utility-in other
words, electric power, burning it. Estonia is a world leader in
Estoniajust entered into an agreement with Jordan to develop
Jordanian oil shale and so on. That's why I introduced the question
of signing an agreement with Brazil, getting President Bush to
enter into two agreements, one for sugar and one for shale, and
then staking out, under existing law, technology sharing and
agreements and co-development in Brazil. But we have much to learn
from Estonia and the tar sands issues and others. There are many
One co-product, by the way, from Colorado shale is trona-soda
ash-which was called nahcolite. The mineral byproduct is very
valuable in terms of fertilizer and other products. There is an
enormous co-product. It was interesting: The Bureau of Land
Management looked at the Exxon application. Exxon wanted a lease,
and Exxon did not put down its data, did not surrender data or
interest in the co-product, and they didn't get the lease. So there
is a valuable co-product in it: soda ash, nahcolite.
Question:My name is
Richard Ranger. I'm with the American Petroleum Institute. How do
you respond to the contention that the main reason shale has not
been developed has been because of economics, because of price,
because of the cyclicality of crude oil prices, which at a couple
of points, perhaps, reached points where companies were induced to
invest in shale technologies as they understood them and then
backed away, given downward price cycles. I think part of the
response is your proposal to purchase shale oil production, or
kerogen production, as you outlined in your talk, but it seems like
you're describing history in a more complicated manner; if this had
been economic to produce, it would have been produced.
Fine:You introduce the whole history, really, in the
question. In the 1960s, Stewart Udall called for shale leases.
There was no interest from industry; American industry was not
interested at that point, because crude oil was $3 per barrel. So
the industry itself, looking at its assets and opportunities on a
world scale by the 1960s, had to compare its rate of return from
other opportunities against shale.
Why did shale fail in 1982? Why did Exxon close down its
operation in Colorado? The slope of supply, the Saudi output up
through the 1980s, again took the price down where it was not
economic against other opportunities. What's interesting about that
is what was economic in shale then and what is economic today.
There are some studies still around, dated in the 1970s, which say
that shale needs $70 a barrel to be economic and compete against
conventional oil. But in testimony in the House Resource Committee
in 2005, Shell said it could do business at $25 per barrel.
So we're in a period when the industry has to essentially take
some risk. What's the risk of price? How do you evaluate forward
prices against risk at this point? The shale story that I see in
all cases that I presented today is that it will return industry a
minimum of 15 percent return on investment, ROI. That will be
indeed possible at prices, we'll say, over $40. And if you see oil
going down to $40, as some analysts do, it is economic.
One of the things that the shale oil industry will look at will
be a floor price to reduce market risk after years of price
volatility. That will be interesting to see, but I think, at this
point, the consensus is that the price of oil has reached a
plateau. Are we going to go back to the days of $20 oil? If you see
that, then you don't invest in shale. But if you see oil at $40
plus, then I think the industry has a real candidate in oil
Daniel Fine, Ph.D., is co-editor of Resource War in 3-D:
Dependence, Diplomacy and Defense and currently associated with the
establishment of a new energy policy center in New Mexico.