Tuesday 24 June 2008

Why UK Natural Gas Prices Will Move North of 100p/Therm This Winter

This is a guest post from Rune Likvern (nrgyman2000 on The Oil Drum). Rune is an independent energy and financial analyst from Norway who has decades of experience from holding various positions within several international oil companies and also runs a blog called "Kveldssong for Hydrokarbonar". When Rune posts on The Oil Drum we usually pay attention to what he has to say.

This post presents the development of the energy mix for UK, how UK in less than a decade went from being a substantial energy exporter to a substantial net energy importer. A more detailed look on what to expect for UK natural gas prices in the near term and a brief discussion on the real options available for future UK energy consumption.

The UK development in energy consumption and energy mix for the years 1965 - 2007 in MTOE. Click to enlarge.
(MTOE; Million Ton Oil Equivalents; 1 MTOE approximates 20 000 bbl/d (oil))
The diagram illustrates how coal in the late 60’s and early 70’s gradually was substituted with oil and increasingly natural gas in the UK energy mix. The introduction of nuclear and natural gas into the energy mix in the early 80’s is based on a combination of factors based on lessons learned during the oil embargo in 1973. The use of oil became more efficient and natural gas, due to adequate indigenous supplies, and nuclear substituted oil for some electricity generation and heating.

In 2007 UK consumed close to 2% of the global total primary energy consumption.

There are few countries where natural gas constitutes such a huge part of the energy consumption. In the recent years natural gas has made up 36 - 38% of UK primary energy consumption (in the US natural gas constitutes 25% of the total primary energy consumption). Among the countries with considerable energy consumption, only in Russia has natural gas a higher relative part (above 50%) of the total energy consumption. (Russia is now listed to have more than 25% of global remaining recoverable natural gas reserves.)

If time (and the TOD editors) permit I will in a future post look into the real possibilities of filling the emerging UK natural gas supply gap with natural gas from Netherlands, Norway, Russia and LNG which for the medium term (meaning the next ten years) seems to be the most viable future supply sources. This will be depressing reading (if you live in UK), so don’t say you were NOT warned!

The recent decline in UK oil consumption is thought to be related to the recent oil price increases. Natural gas consumption is sensitive to weather (temperature), which means heating requirements, and of course a competitive price.

I am in the process of drafting a post for TOD Europe comparing the development in energy/oil consumption and production for the G-7 countries (Canada, France, Germany, Italy, Japan, UK and US) and the BRIC (Brazil, Russia, India and China) members. One of the interesting observations from this study, so far, is that it looks like the G-7 countries oil consumption is very sensitive to relative high upward price movements of oil, like in the 70’s and 80’s and now most recently.

The UK development in energy consumption and energy mix for the years 1965 - 2007 in MTOE. Click to enlarge.
(MTOE; Million Ton Oil Equivalents; 1 MTOE approximates 20 000 bbl/d (oil))

The above diagram shows the relative development of primary energy sources within the energy mix for the years 1965 - 2007 for UK. Back in 1965 coal was the main energy source for UK delivering around 60% of the primary energy consumption. Over the years coal has gradually been substituted with mainly natural gas and nuclear and presently coal makes up less than 20% of total UK primary energy consumption.


The development in net energy exports and imports split on energy sources for UK for the years 1981 - 2007 in MTOE. Click to enlarge.
(MTOE; Million Ton Oil Equivalents; 1 MTOE approximates 20 000 bbl/d (oil))

Through a period of 25 years the UK was a net oil exporter, which peaked with the production in 1999. 6 years later, in 2005, UK again became a net oil importer and the UK oil production from the North Sea is now generally thought to be in irreversible decline (with expected decline rates of 8 - 10% annually), suggesting future growth in oil imports if consumption stays at present levels. Even if indigenous supplies of oil are in decline, this may be overcome with a combination of increased imports and improved efficiencies in the use of oil.

The real near term challenge to UK energy supplies is identified to be natural gas supplies.

Natural gas has since the early 70’s become the most dominant UK primary energy source based upon indigenous supplies. The UK was a net exporter of natural gas (to Continental Europe) from 1995 - 2003. UK natural gas production peaked in 2000 and the UK again became a net natural gas importer as of 2004 and in 2007 UK net imports was more than 20% of its natural gas consumption.

In 1984 UK became a net importer of coal. UK coal reserves is listed to have a R/P ratio of 9 according to BP Statistical Review 2008, meaning that present reserves will last in 9 years at present rate of production.


It is generally observed (and acknowledged) that natural gas prices tend to follow the path of the oil prices with a time lag. Some analysts have even predicted that natural gas prices could decouple from oil prices sometime in the future.

Studying the price ratio of nat gas versus oil on a heating value basis (per million Btu) tells an interesting story.

The development in the price ratio between natural gas and oil. Click to enlarge.

The above diagram shows the development in the price ratio between natural gas and oil against the left y-axis for;

  • LNG (delivered in Japan)
  • Natural gas (cif) delivered to EU
  • Natural gas at Henry Hub (USA)
  • Natural gas at Heren NBP (National balancing Point) UK
In the diagram is also the development in the oil price shown in US$ 2007 against the right y-axis. Note how when oil prices were low natural gas based on energy content became relatively more expensive than oil and vice versa.

When the energy price ratio is below 1.0 this indicates that natural gas based on energy is cheaper than oil and vice versa when this ratio becomes greater than 1.0.

Japan seems recently to increasingly profit from the run up in oil prices as LNG purchased on long term contracts becomes relatively cheaper as a source of energy based on heat content. Developers of LNG facilities generally preferred long term contracts due to the capital intensive nature of the LNG business as this also increases the predictability for return on the investment and a steady profit flow. This is also one of the reasons why it has been challenging to establish a well functioning spot market for LNG.

Historically, and for those of the readers who are interested, 1 (one) barrel of oil has been converted to approximately 6 (six) million Btu of natural gas based on price. This means that if oil is priced at US$132/bbl, 1 million Btu of natural gas should be expected to cost US$22 at the trading point or beach.
(1 000 000 Btu = 10 Therm; 1 Therm = 100 000 Btu)

The diagram illustrates that the recent years run up in oil prices, as from 2004, have made natural gas increasingly and relatively cheaper than oil (in the diagram it can be observed how the hurricanes Katrina and Rita affected US natural gas prices in absolute terms and relative to oil in 2005). Note also how natural gas became relatively expensive as oil prices fell.

So far in 2008 the recent runs up in the oil prices have further encouraged an increase in the demand for natural gas. The result from this demand growth may now be observed in the recent price increases for natural gas at trading points like Henry Hub (USA) and NBP (UK)

Consumers who have dual fuel capabilities (like electrical power plants normally used for peak shaving) will tend to alternate between natural gas and distillates based on price.

The UK was a net exporter of natural gas form the years 1995 to 2003 (ref the diagram above illustrating the development for UK as a net energy exporter and net energy importer) and how this increased with the opening of the Interconnector between Bacton and Zebrugge in Belgium in 1998.

For UK owners of natural gas the liquid market of Continental Europe was in close reach and prices on the beach on Continental Europe was on average 20% higher than in the UK (ref the above diagram) and serving this market did not pose any big technical challenges, financial or political risks.

The lower nat gas prices at the beach for UK domestic users, both household and industrial, also gave UK industry a competitive edge (relative to consumers in Continental Europe and even in the US) and made comfortable amounts of energy available and affordable for households.


In 2007 the UK natural gas market became flooded with natural gas thus depressing prices. This flood of natural gas resulted from several sellers, like Norway, Holland (BBL) and LNG traders, had perceived an increased tightness in the UK market (due to declines in UK indigenous supplies and expected growth in consumption) for the heating season 2006/2007 and positioned them to reap the profits from this tightness. What happened, as these players seems to have been unaware of each other (which should be the case in an ideal liberalized marketplace), was that supply increased more than demand grew and in addition the weather became milder than normal, a combination and a recipe for depressing natural gas prices.

UK will increasingly have to cover their natural gas consumption through imports, which suggests that an era of cheap natural gas, which has also acted as a competitive edge, increasingly will have to become harmonized with natural gas prices on Continental Europe which UK increasingly will have to bid against to secure supplies. Indirectly this may now be observed as less natural gas is exported to Continental Europe in the summer months through the Interconnector.

  • With reference to the diagram showing the development in the energy price ratio between natural gas and oil and establishing a reference to 2007 levels, further assuming harmonization against natural gas prices on Continental Europe, this should suggest that nat gas prices in the UK at the beach has to come up 50 - 60% relative to 2007 levels. On average in 2007 these prices were 30 p/therm at the beach (the natural gas price has huge seasonal swings).
  • Oil prices in 2007 was on average above US$72/bbl, and so far in 2008 the average oil price has been close to US$110/bbl and recently it seems like it has found support at US$130 - 140/bbl. This now suggests that the natural gas prices should put on an additional 80 - 90%.
The above points suggest that natural gas prices on average in 2008 in UK will have to put on 150 - 200% resulting in average prices through 2008 of 75 - 90 p/therm at the beach. Recently natural gas is now trading at 60 - 65 p/therm.

It is difficult to predict the weather for the upcoming heating season and this is often the one factor having the greatest effect on short term natural gas prices. Given the seasonal nature of natural gas consumption it should come as no surprise if UK natural gas prices at the beach move north of 100 p/therm before the upcoming Christmas.

For an average household consuming 600 - 700 therm/annually (18 - 21 000 kWh/a) this would translate into an increase of the households natural gas bill of £3 - 400 this year relative to 2007.


In this post it has been shown why UK households and industries should expect to increasingly be hammered by growing energy prices.

In less than ten years UK went from being a considerable energy exporter to becoming in size a similar energy importer. In 2007 UK imported more than 20% of its energy needs. This import is now forecast to grow at an annual rate of 13 - 15 MTOE (250 - 300 kboe/d; kilo barrels of oil equivalents a day) or 6 - 8% in the years ahead. What makes UK such an interesting subject from an energy standpoint is that the UK has had to transit from a major energy exporter to an energy importer with a speed never seen before for any other comparable economy. There are economies that are and have been more reliant on energy imports than UK (like Germany, France, Italy, Japan to name a few) and these have from these realities developed (seemingly) long term successful strategies involving central government’s involvement to cope with this energy reality.

This post has further shown that the UK energy mix is dominated by natural gas and thus made it vulnerable for potential future supply crunches. To revise the energy mix is a time consuming process and if the world has passed, is on or close to its apex for liquid energy supplies, these will not constitute a sustainable alternative to natural gas for the UK energy mix.

I have been informed that after a coal mine has been closed it may take ten years to recommission it for operations. Coal is mainly used for electricity generation and could of course be used for both heating and cooking purposes, which suggests changing housing appliances and stoves to accommodate this. To base the future UK energy mix on more coal results in future growth in coal imports.

Nuclear energy comes with delicate political maneuvering as the public needs to familiar itself with this alternative. Further needs nuclear plants a lead/construction time of approximately 10 years from approval have been granted.

I have not presented anything about renewables.

(I consequently refuse to use the expression “renewable energy”, as people who are familiar with the laws of thermodynamics know that energy by nature is NOT renewable. Energy may be transformed from one form into another.)

So called renewables will play a role in the future energy mix, but their impact on energy supplies must realistically be viewed against the potent and versatile nature of oil and natural gas.

Like USA talks about its oil addiction it looks like UK needs to talk about its natural gas addiction.

Given the time frame and not least options available to redesign the UK energy mix it looks like the UK “energy supply war” may have been lost before most people became aware that there was one on.

Nature enforces its own limits and a realistic look on the future energy options available for UK, energy conservation and power down now seems the most likely. This is of course a harsh message for any politician to convey to the public as it requires talent and leadership which there generally seems to be a universal deficit of......even in good times.

Friday 13 June 2008

BP CEO: oil markets will save us

The CEO of BP, Tony Hayward, has published, on the occasion of the publication of BP's statistical yearbook, an Op-Ed in the Financial Times with a pretty self-explicit title: Let the markets solve the energy crisis. But it's also very devious, as his ode to markets allows him to mix reasonable arguments with highly toxic ones, and it's going to be very hard to make the distinction that he is correct on some respects but not in others...
Basically his arguments boil down to 3 points: there is no speculation (prices are justified by fundamentals, markets work fine), renewable energy is not serious (too small, mostly), and there is no peak oil (plenty of reserves around). and of course, his solution is simple: oil majors are ready to invest and let market forces solve the supply problem, but political obstacles prevent them, and governments must therefore help by removing these.
What is true is that speculation is not to blame, and that there are political obstacles to investment today. The rest is not quite so true. And that mix, which I expect is deliberate, has one main subtext: "don't worry" (and don't try to move off oil).

OK, here's the text in full.

Thursday 6 December 2007

What Will We Eat as the Oil Runs Out?

December 2007
by Richard Heinberg

What Will We Eat as the Oil Runs Out?
The Lady Eve Balfour Lecture, November 22, 2007

Our global food system faces a crisis of unprecedented scope. This crisis, which threatens to imperil the lives of hundreds of millions and possibly billions of human beings, consists of four simultaneously colliding dilemmas, all arising from our relatively recent pattern of dependence on depleting fossil fuels.

The first dilemma consists of the direct impacts on agriculture of higher oil prices: increased costs for tractor fuel, agricultural chemicals, and the transport of farm inputs and outputs.

The second is an indirect consequence of high oil prices - the increased demand for biofuels, which is resulting in farmland being turned from food production to fuel production, thus making food more costly.

The third dilemma consists of the impacts of climate change and extreme weather events caused by fuel-based greenhouse gas emissions. Climate change is the greatest environmental crisis of our time; however, fossil fuel depletion complicates the situation enormously, and if we fail to address either problem properly the consequences will be dire.

Finally comes the degradation or loss of basic natural resources (principally, topsoil and fresh water supplies) as a result of high rates, and unsustainable methods, of production stimulated by decades of cheap energy.

Each of these problems is developing at a somewhat different pace regionally, and each is exacerbated by the continually expanding size of the human population. As these dilemmas collide, the resulting overall food crisis is likely to be profound and unprecedented in scope.

read more

Friday 23 November 2007

Life after the oil crash .... ( DEFCON 1)

Dear Reader,

Civilization as we know it is coming to an end soon. This is not the
wacky proclamation of a doomsday cult, apocalypse bible
prophecy sect, or conspiracy theory society. Rather, it is the
scientific conclusion of the best paid, most widely-respected
geologists, physicists, bankers, and investors in the world. These
are rational, professional, conservative individuals who are
absolutely terrified by a phenomenon known as global "Peak Oil."

"Are We 'Running Out'? I Thought There Was 40 Years of the Stuff Left"

Oil will not just "run out" because all oil production follows a bell
curve. This is true whether we're talking about an individual field,
a country, or on the planet as a whole.
Oil is increasingly plentiful on the upslope of the bell curve,
increasingly scarce and expensive on the down slope. The peak of
the curve coincides with the point at which the endowment of oil
has been 50 percent depleted. Once the peak is passed, oil
production begins to go down while cost begins to go up.

read more ....

IPCC Fourth Report Summary

The IPCC's Synthesis Report, the fourth and final installment from the Intergovernmental Panel on Climate Change, is due in a few weeks. Just the Summary for Lawmakers is more than meaty enough to consume your idle reading time this weekend. Thankfully, our staff has extracted the key points and boiled 23 pages down to 2.

Why We Can't Wait

Why We Can't Wait


This is an adaptation of a talk delivered February 26 at the National Press Club.

There's a huge gap between what is understood about global warming by the relevant scientific community and what is known about global warming by those who need to know: the public and policy-makers. We've had, in the past thirty years, one degree Fahrenheit of global warming. But there's another one degree Fahrenheit in the pipeline due to gases that are already in the atmosphere. And there's another one degree Fahrenheit in the pipeline because of the energy infrastructure now in place--for example, power plants and vehicles that we're not going to take off the road even if we decide that we're going to address this problem.

The Energy Department says that we're going to continue to put more and more CO2 in the atmosphere each year--not just additional CO2 but more than we put in the year before. If we do follow that path, even for another ten years, it guarantees that we will have dramatic climate changes that produce what I would call a different planet--one without sea ice in the Arctic; with worldwide, repeated coastal tragedies associated with storms and a continuously rising sea level; and with regional disruptions due to freshwater shortages and shifting climatic zones.

I've arrived at five recommendations for what should be done to address the problem. If Congress were to follow these recommendations, we could solve the problem. Interestingly, this is not a gloom-and-doom story. In fact, the things we need to do have many other benefits in terms of our economy, our national security, our energy independence and preserving the environment--preserving creation.

First, there should be a moratorium on building any more coal-fired power plants until we have the technology to capture and sequester the CO2. That technology is probably five or ten years away. It will become clear over the next ten years that coal-fired power plants that do not capture and sequester CO2 are going to have to be bulldozed. That's the only way we can keep CO2 from getting well into the dangerous level, because our consumption of oil and gas alone will take us close to the dangerous level. And oil and gas are such convenient fuels (and located in countries where we can't tell people not to mine them) that they surely will be used. So why build old-technology power plants if you're not going to be able to operate them over their lifetime, which is fifty or seventy-five years? It doesn't make sense. Besides, there's so much potential in efficiency, we don't need new power plants if we take advantage of that.

Second, and this is the hard recommendation that no politician seems willing to stand up and say is necessary: The only way we are going to prevent having an amount of CO2 that is far beyond the dangerous level is by putting a price on emissions. In order to avoid economic problems, it had better be a gradually rising price so that the consumer has the option to seek energy sources that reduce his requirement for how much fuel he needs. And that means we should be investing in energy efficiency and renewable energy technologies at the same time. The result would be high-tech, high-paid jobs. And it would be very good for our energy independence, our national security and our balance of payments.

But a price on carbon emissions is not enough, which brings us to the third recommendation: We need energy-efficiency standards. That's been proven time and again. The biggest use of energy is in buildings, and the engineers and architects have said that they can readily reduce the energy requirement of new buildings by 50 percent. That goal has been endorsed by the US Conference of Mayors, but you can't do it on a city-by-city basis. You need national standards. The same goes for vehicle efficiency. We haven't had an improvement in vehicle efficiency in twenty-five or thirty years. And our national government is standing in court alongside the automobile manufacturers resisting what the National Research Council has said is readily achievable--a 30 percent improvement in vehicle efficiency, which California and other states want to adopt.

The fourth recommendation--and this is probably the easiest one--involves the question of ice-sheet stability. The old assumption that it takes thousands or tens of thousands of years for ice sheets to change is clearly wrong. The concern is that it's a very nonlinear process that could accelerate. The west Antarctic ice sheet in particular is very vulnerable. If it collapses, that could yield a sea-level rise of sixteen to nineteen feet, possibly on a time scale as short as a century or two.

The information on ice-sheet stability is so recent that the Intergovernmental Panel on Climate Change report does not adequately address it. The IPCC process is necessarily long and drawn out. But this problem with the stability of ice sheets is so critical that it really should be looked at by a panel of our best scientists. Congress should ask the National Academy of Sciences to do a study on this and report its conclusions in very plain language. The National Academy of Sciences was established by Abraham Lincoln for just this sort of purpose, and there's no reason we shouldn't use it that way.

The final recommendation concerns how we have gotten into this situation in which there is a gap between what the relevant scientific community understands and what the public and policy-makers know. A fundamental premise of democracy is that the public is informed and that they're honestly informed. There are at least two major ways in which this is not happening. One of them is that the public affairs offices of the science agencies are staffed at the headquarters level by political appointees. While the public affairs workers at the centers are professionals who feel that their job is to translate the science into words the public can understand, unfortunately this doesn't seem to be the case for the political appointees at the highest levels. Another matter is Congressional testimony. I don't think the Framers of the Constitution expected that when a government employee--a technical government employee--reports to Congress, his testimony would have to be approved and edited by the White House first. But that is the way it works now. And frankly, I'm afraid it works that way whether it's a Democratic administration or a Republican one.

These problems are worse now than I've seen in my thirty years in government. But they're not new. I don't know anything in our Constitution that says that the executive branch should filter scientific information going to Congressional committees. Reform of communication practices is needed if our government is to function the way our Founders intended it to work.

The global warming problem has brought into focus an overall problem: the pervasive influence of special interests on the functioning of our government and on communications with the public. It seems to me that it will be difficult to solve the global warming problem until we have effective campaign finance reform, so that special interests no longer have such a big influence on policy-makers.

Wednesday 21 November 2007


Robert L. Hirsch, SAIC, Project Leader
Roger Bezdek, MISI
Robert Wendling, MISI
February 2005
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
disclosed, 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.
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
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.
n 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 (EOR), 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 wellestablished
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.
mportant 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 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 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.
n 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.
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-1.1 Such projections are
fraught with uncertainties because of poor data, political and institutional selfinterest,
and other complicating factors. The bottom line is that no one knows
with certainty when world oil production will reach a peak,2 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
1A more detailed list is given in the following chapter in Table II-2.
2 In this study we interchangeably refer to the peaking of world conventional oil production as “oil
peaking” or simply as “peaking.”
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
• 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
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.
n 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
• What can be done to ensure that prudent mitigation is
initiated on a timely basis?
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
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
3Portions of this chapter are taken from Hirsch, R.L. "Six Major Factors in Energy Planning".
U.S. Department of Energy. National Energy Technology Laboratory. March 2004.
managed oil fields, it is often 10-20 percent more than what is available at lower
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 finding new ones, capable of producing
sufficient quantities of oil to both compensate for shrinking production from older
fields and to provide the increases demanded by the market.
C. Production Peaking
World oil demand is expected to grow 50 percent by 2025.4 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 remaining.
Peaking means that the rate of world oil production cannot increase; it also
means that production will thereafter decrease with time.
4U.S. Department of Energy, Energy Information Administration, International Energy Outlook –
2004, April 2004.
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
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
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
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.5 (Unconventional oil production
will be discussed in Chapter VI).
E. Oil Resources6
Consider the world resource of conventional oil. In the past, higher prices led to
increased estimates of conventional oil reserves worldwide. However, this pricereserves
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
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 II-1, which shows the difference between annual world oil
reserves additions minus annual consumption.7 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
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
5U.S. Department of Energy, Energy Information Administration, International Energy Outlook –
2004, April 2004.
6 Total oil in place is called the “resource.” However, only a part of the resource can be
produced, because of geological complexities and economic limitations. That which is
realistically recoverable is called “reserves,” which varies within limits depending on oil prices.
7Aleklett, K. & Campbell, C.J. "The Peak and Decline of World Oil and Gas Production". Uppsala
University, Sweden. ASPO web site. 2003.
Figure II-1. Net Difference Between Annual World Oil Reserves Additions
and Annual Consumption
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 2025.8
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.
8U.S. Department of Energy, Energy Information Administration, International Energy Outlook –
2004, April 2004.
1940 2000
Billions of
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 US
production was in part impacted by the availability of large volumes of relatively
low cost oil from the Middle East.
Figure II-2 shows EIA data for Lower 48 oil production,9 to which trend lines have
been added that will aid our scenarios analysis later in the report. 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.
(Billions of
Figure II-2. U.S. Lower 48 Oil Production, 1945-2000
Figure II-3 shows Lower 48 historical oil production with oil prices and technology
trends added. 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
9U.S. Department of Energy, Energy Information Administration, Long Term World Oil Supply,
April 18, 2000.
1950 1960 1970 1980 1990 2000
1973 Embargo
1979 Iranian Crisis 1986 Price Crash
1991 Iraq War
Actual (EIA)
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, as
Figure II-3 shows, 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.10
1950 1960 1970 1980 1990 2000
Figure II-3. Lower 48 Oil Production and Oil Prices
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
10 The US Lower 48 experience occurred over a long period characterized at different times by
production controls (Texas Railroad Commission), price and allocation controls (1970s), free
market prices (since 1981), wild price swings, etc., as well as higher prices and advancing
technology. Nevertheless, production peaked and moved into a relatively constant rate of
Improvement in Oil
Field Technology
Billions of barrels / year
2002 dollars per barrel
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
Projected Date Source of Projection Background & Reference
2006-2007 Bakhitari, A.M.S. Iranian Oil Executive11
2007-2009 Simmons, M.R. Investment banker 12
After 2007 Skrebowski, C. Petroleum journal Editor 13
Before 2009 Deffeyes, K.S. Oil company geologist (ret.) 14
Before 2010 Goodstein, D. Vice Provost, Cal Tech 15
Around 2010 Campbell, C.J. Oil company geologist (ret.) 16
After 2010 World Energy Council World Non-Government Org.17
2010-2020 Laherrere, J. Oil company geologist (ret.) 18
2016 EIA nominal case DOE analysis/ information19
After 2020 CERA Energy consultants 20
2025 or later Shell Major oil company 21
No visible peak Lynch, M.C. Energy economist22
11Bakhtiari, A.M.S. "World Oil Production Capacity Model Suggests Output Peak by 2006-07."
OGJ. April 26, 2004.
12Simmons, M.R. ASPO Workshop. May 26, 2003.
13Skrebowski, C. "Oil Field Mega Projects - 2004." Petroleum Review. January 2004.
14Deffeyes, K.S. Hubbert’s Peak-The Impending World Oil Shortage. Princeton University Press.
15Goodstein, D. Out of Gas – The End of the Age of Oil. W.W. Norton. 2004
16Campbell, C.J. "Industry Urged to Watch for Regular Oil Production Peaks, Depletion Signals."
OGJ. July 14, 2003.
17Drivers of the Energy Scene. World Energy Council. 2003.
18Laherrere, J. Seminar Center of Energy Conversion. Zurich. May 7, 2003
19DOE EIA. "Long Term World Oil Supply." April 18, 2000. See Appendix I for discussion.
20Jackson, P. et al. "Triple Witching Hour for Oil Arrives Early in 2004 – But, As Yet, No Real
Witches." CERA Alert. April 7, 2004.
21Davis, G. "Meeting Future Energy Needs." The Bridge. National Academies Press. Summer
22Lynch, M.C. "Petroleum Resources Pessimism Debunked in Hubbert Model and Hubbert
Modelers’ Assessment." Oil and Gas Journal, July 14, 2003.
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 III-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.23 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.24 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.
23U.S. Department of Commerce, Bureau of Economic Analysis, National Income and Product
Accounts, 2004.
24U.S. Department of Transportation, Federal Highway Administration, Highway Statistics, 2004.
Figure III-1. U.S. Petroleum Consumption by Sector, 1973-200325
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
25U.S. Department of Energy, Energy Information Administration, Monthly Energy Review, 2004.
quadrillion Btu
Electric Power
feedstocks used to produce non-fuel products in the petroleum and chemical
Table III-1.
Detailed Consumption of Petroleum in the U.S.
by Fuel Type and Sector - 200326
(Thousand of barrels per day)
Residential Commercial Industrial Transportation Electric
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 lead 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.
26U.S. Department of Energy, Energy Information Administration, Detailed annual petroleum
consumption accounts by fuel and sector at www,eia.doe,gov, 2004
Recent studies show that one half of the1990-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.27
Table III-2.
U.S. Capital Stock Profiles
Light Heavy Air
Autos Trucks Trucks Carriers
Oil consumption (MM bpd)28 4.9 3.6 3.0 1.1
Share of the U.S. total 25% 18% 16% 6%
Current cost of net capital stock
(billion $)29
$571 B
$435 B
$686 B
$110 B
Fleet size30
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,
27 Because of the lack of national average "replacement value" estimates, current-cost net capital
stock provides a suitable substitute for the estimates. Given the capital equipment depreciation
schedule used, the total replacement value of the capital stock is projected to be 4.5 times higher
than the current-cost net value
28U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook - 2004,
and Oak Ridge National Laboratory, Transportation Energy Data Book #23, 2003.
29 U.S. Department of Commerce, Bureau of Economic Analysis, Fixed Asset Tables, 1992-2002.
The estimate of net stock includes an adjustment for depreciation, defined as the decline in value
of the stock of assets due to wear and tear, obsolescence, accidental damage, and aging. For
most types of assets, estimates of depreciation are based on a geometric decline in value.
30 Oak Ridge National Laboratory, Transportation Energy Data Book #23, 2003; and U.S.
Department of Transportation, Bureau of Transportation Statistics, Active Air Carrier Fleet; and
Management Information Services, Inc., 2004.
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, 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.31 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, electrichybrid
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 program" 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.32
31The largest remaining oil-consuming capital stock resides in the industrial sector. Oil
consumption in the industrial sector is diverse, making it difficult to target specific capital stock
and identify potential efficiency efforts or potential technology advancements. The largest oilconsuming
industries include the chemical, lumber and wood, paper products, and petroleum
industry itself. Functional usage of oil in the industry includes heat, process heat, power,
feedstock, and lubrication. Finally, the equipment spans hundreds of disparate types of in situ
engines, turbines, and agricultural, construction, and mining machinery.
32U.S. Department of Transportation, Bureau of Transportation Statistics, American Travel Survey
Profile and Oak Ridge National Laboratory, Transportation Energy Data Book - 2003.
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 is
no alternative energy sources that compete economically with oil in the
transportation sector.”33 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.
33 U.S. Department of Energy, Energy Information Administration. International Energy Annual,
2004. April 2004.
A. Previous Oil Supply Shortfall and Disruptions
There have been over a dozen global oil supply disruptions34 over the past halfcentury,
as summarized in Figure IV-1.
Figure IV-1. Global Oil Supply Disruptions: 1954-2003
• 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.
34U.S. Department of Energy, Energy Information Administration, “Latest Oil Supply Disruption
Information,“ eia.doe.gov, 2004; U.S. Department of Energy, Energy Information Administration,.
“World Oil Market and Oil Price Chronologies: 1970-2003,” March 2004; U.S. Department of
Energy, Energy Information Administration, “Global Oil Supply Disruptions Since 1951”, 2001;
U.S. Department of Energy, Energy Information Administration, Annual Energy Review,
2002;U.S. Department of Energy, Energy Information Administration, International Petroleum
Monthly, April 2004.
avg. gross supply shortfall (mdb)
shortfall as a percent of production
left axis right axis
• 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
might 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.35 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.”36 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 play a key role in the global economy, since the major impact of an oil
supply disruption is higher oil prices.37 Oil price increases transfer income from
35This is verified by the extensive literature review conducted by Donald W. Jones and Paul N.
Leiby, “The Macroeconomic Impacts of Oil Price Shocks: A Review of the Literature and Issues,”
Oak Ridge National Laboratory, January 1996, and by Donald W. Jones, Paul N. Leiby, and Inja
K Paik, “Oil Price Shocks and the Macroeconomy: What Has Been Learned Since 1996, The
Energy Journal, 2003.
36See, for example, Leonardo Maugeri, “Oil: Never Cry Wolf – Why the Petroleum Age is Far
From Over, “ Science, Vol. 304, May 21, 2004, pp. 1114-1115; Michael C. Lynch, “Closed Coffin:
Ending the Debate on ‘The End of Cheap Oil,’ A Commentary,” DRI/WEFA, September 2001;
Michael C. Lynch “Farce This Time: Renewed Pessimism About Oil Supply, 2000; Bjorn
Lomborg, “Running on Empty?” Guardian, August 16, 2001; Mark Mills, “Stop Worrying About Oil
Prices,” 2001, fossilfuels.org; Jerry Taylor, “Markets Work Magic,” Cato Institute, January 2002;
Rethinking Emergency Energy Policy, U.S. Congressional Budget Office, December 1994.
37This is the consensus of virtually every rigorous analysis of the problem; see, for example, the
International Monetary Fund study conducted by Benjamin Hunt, Peter Isard, and Douglas
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.38 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
As illustrated in Figure IV-2, 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.39 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:
Saxton, “The Macroeconomic Effects of Oil Price Shocks,” National Institute Economic Review
No. 179, January 2002.
38“The Impact of Higher Oil Prices on the World Economy,” OECD Standing Group on Long-Term
Cooperation, 2003.
39See Lee, Ni, and Ratti, op. cit., and J.D. Hamilton and A.M. Herrera “Oil Shocks and Aggregate
Macroeconomic Behavior: The Role of Monetary Policy,” Journal of Money, Credit and Banking,
Figure IV-2. Oil Prices and U.S. Recessions: 1969-200340
• The loss suffered by the OECD countries in the 1974/-75 recession
amounted to $350 billion (current dollars) / $1.1 trillion 2003 dollars,
although part of this loss was related to factors other than oil
• 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 1981-82.42
• 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.
40 U.S. Joint Economic Committee and Management Information Services, Inc., 2004.
41 This totals about $1.1 trillion in 2003 dollars and was equivalent to a once-and-for-all reduction
in real GDP of about seven percent; however, part of that loss was likely attributable to structural
and cyclical economic factors unrelated to the oil-price shock. See Faith Bird, “Analysis of the
Impact of High Oil Price on the Global Economy,” International Energy Agency, 2003.
42 These losses totaled about $700 billion and $1.1 trillion, respectively in 2003 dollars. Losses of
this magnitude are significant and represent the difference between vibrant, growing economies
and economies in deep recession. There is considerable debate as to precisely how much of
these losses was attributable to the oil price shocks, to fiscal and monetary policies, and to other
recession $ ('03) per barrel
• 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.43
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
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, the higher the
price increases; the longer the shortfall, the greater will be the adverse economic
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 nations will likely be even worse off.44
43See Bird, op. cit., and OECD Standing Group on Long-Term Cooperation, op. cit.
44A $10/bbl. increase in oil prices, if sustained for a year, will reduce global GDP by 0.6 percent,
ignoring the secondary effects on confidence, stock markets, and policy responses; see Bird, op.
cit. A sustained increase of $10/bbl. would reduce economic growth by 0.5 percent in the
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.45
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.
f 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.46 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.47 Continuing oil shortages will likely have disruptive inter-sectoral, interindustrialized
countries and by 0.75 percent or more in the developing countries; see Ibid., OECD
Standing Group on Long-Term Cooperation, op. cit., and International Monetary Fund, World
Economic Outlook, September 2003. Larger oil price increases will have even more severe
economic effects.
45K.A. Mork, “Business Cycles and the Oil Market,” Energy Journal, special issue, 1994, pp. 15-
46See Mark Hooker, “Are Oil Shocks Inflationary? Asymmetric and Nonlinear Specification
Versus Changes In Regime,” Federal Reserve Board, December 1999.
47Hillard Huntington, “Energy Disruptions, Interfirm Price Effects, and the Aggregate Economy,”
Energy Modeling Forum, Stanford University, September 2002; S.J. Davis, and J. Haltiwanger,
industry, and inter-regional effects, and the sectors that are (both directly and
indirectly) oil-dependant could be severely impacted.48
Monetary policy is more effective in controlling the inflationary effects of a supply
disruption than in averting related recessionary effects.49 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.50
“Sectoral Job Creation and Destruction Response to Oil Price Changes,” Journal of Monetary
Economics, Vol. 48, 2001, pp. 465-512.
48“Demand destruction” has often been identified as a solution, since oil price increases resulting
from a disruption will reduce demand and this will moderate further price increases. However,
demand is reduced because the economy is devastated and large numbers of jobs are lost.
Demand destruction – a polite word for economic and job losses – is the problem, not the
solution. See the discussion in Roger Bezdek and Robert Wendling, “The Case Against Gas
Dependence,” Public Utilities Fortnightly, Vol. 142, No. 4, April 2004, pp. 43-47.
49Joint Economic Committee of the U.S. Congress, “10 Facts About Oil Prices,” March 2003;
Mark Hooker, “Oil and the Macroeconomy Revisited,” Federal Reserve Board, August 1999.
50Nevertheless, during disruptions, public actions may be required to address societal risks. This
creates a dilemma: In the event of a severe shortfall of long duration, government intervention of
some sort may be required, and allocation plans to moderate the effects of this shortfall will likely
be advocated. However, given the experience of the 1970s, many of the policies enacted in a
crisis atmosphere will be, at best, sub-optimal. For example, in 1980, the Federal government
developed a Congressionally-mandated stand-by U.S. gasoline rationing plan which could, in
some form, be implemented; see Standby Gasoline Rationing Plan, U.S. Department of Energy,
Washington, D.C., June 1980.
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.” 51
• 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.” 52
• 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 2020.53
51National Petroleum Council. Meeting the Challenges of the Nation's Growing Natural Gas
Demand. December 1999.
52Esser, R. et al. Natural Gas Productive Capacity Outlook in North America - How Fast Can It
Grow? Cambridge Energy Research Associates, Inc. 2001.
53U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook 2000.
December 1999.
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 US downturn.”54
• Raymond James & Associates finds that “Natural gas production continues to
drop despite a 20 percent increase in U.S. drilling activity since April 2003.”55
“U.S. natural gas production is heading firmly downwards…”56
• “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...”57
• 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.”58
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.”59
54CERA Advisory Services. The Worst is Yet to Come: Diverging Fundamentals Challenge the
North American Gas Market. Cambridge Energy Research Associates, Inc. Spring 2004.
55Industry Trends (quoting Raymond James & Associates). OGJ. June 7, 2004.
56Adkins, J.M. et al. "Energy Industry Brief". Raymond James & Associates. May 17, 2004.
57"Lehman Says US 1Q Gas Production Fell By 5.3%". Dow Jones. May 12, 2004.
58National Petroleum Council. Balancing Natural Gas Policy – Fueling the Demands of a Growing
Economy: Volume I – Summary of Findings and Recommendations. September 25, 2003.
59Reuters. "Alberta Gas Output Falling Despite Record Drilling". June 6, 2004.
D. U.S. Natural Gas Price History
EIA data show that U.S. natural gas prices were relatively stable in constant
dollars from 1987 through1998.60 However, beginning in 2000, prices began to
escalate -- they were roughly 50 percent higher in 2000 compared to 1998.61
Skipping over the recession years of 2001 and 2002, prices in late 2003 and
early 2004 further increased roughly 25 percent over 2000.62
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 2007.63
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).64
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.65 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.66 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.
60Natural Gas Markets and EIA's Information Program March 2000.
61U.S. Department of Energy, Energy Information Administration, Natural Gas Annual 2002.
62U.S. Department of Energy, Energy Information Administration, "Natural Gas Navigator." Last
Updated 5/6/04.
63CERA Advisory Services. "The Worst is Yet to Come: Diverging Fundamentals Challenge the
North American Gas Market". Cambridge Energy Research Associates, Inc. Spring 2004.
64 The Alaska natural gas pipeline is at least 10 years from operation, maybe longer.
65 Flalka, J.J. & Gold, R. "Fears of Terrorism Crush Plans For Liquefied-Gas Terminals." The
Wall Street Journal. May 14, 2004.
66 Bender, B. "DistriGas Contests Hazard Study Findings." Boston Globe. June 2, 2004.
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 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
• 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
• 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.
f 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?
f 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?
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 oilconsuming
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
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. 67
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.68
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 onthe-
road U.S. market share by 2015.69 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
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
67Harvan, R. "Diesel Use Surging". World Refining. June 2004.
68 Consumer Reports. August 2004. Page 49.
69National Research Council. The Hydrogen Economy: Opportunities, Costs, Barriers, and R & D
Needs. National Academy Press. 2004.
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.70 The feasibility and cost of such retrofits are not known, so
we consider this option to be speculative.
t 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.71
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.72
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.73 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
70Kerwin, K. "Chrysler Puts Some Muscle on the Street". Business Week. June 7, 2004.
71Press release. Eaton Corp., March 30, 2004.
72Press release. National Renewable Energy Technology Laboratory, February 8, 2002.
73Homes, S. "A Silver Lining for Boeing". Business Week. May 24, 2004.
of factors, including 1) actual and expected future oil prices; 2) production history,
geology, and status of the reservoir; 3) cost and character of productionenhancing
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.
mproved 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.74
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
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).75 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.
74Williams, B. "Progress in IOR technology, economics deemed critical to staving off world's oil
production peak". OGJ. August 4, 2003.
75Williams, B. "Progress in IOR technology, economics deemed critical to staving off world's oil
production peak". OGJ. August 4, 2003; National Research Council. Fuels to Drive Our Future.
National Academy Press. 1990.; "EOR Continues to Unlock Oil Resources". OGJ. April 12,
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. This concept is notionally shown in Figure IV-1.
Figure VI-1. The Timing of EOR Applications
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
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 total, the amount of oil
estimated to be economically recoverable is of the order of 600 billion barrels.76
This relatively low fraction is in large part due to the extremely difficult task of
extracting these oils.77
76Economists will argue that this amount will increase with higher world oil prices, which is almost
certainly correct. However, without careful analysis, estimation of the increased reserves would
be strictly speculation.
77These numbers are subject to revision upwards or downwards depending on future geological
findings, advancing technology, or higher oil prices. Williams, B. "Heavy Hydrocarbons Playing
Key Role in Peak Oil Debate, Future Supply". OGJ. July 28, 2003.
Time - Decades
Normal Production Due
to Primary & Secondary
Enhanced by EOR
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.78
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.79 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.80
n 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 water81 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
78 Gray, D. "Oil Sands Conference Report". Mitretek. May 24, 2004.
79 "Oil Sands Technology Roadmap". Alberta Chamber of Resources. January 2004.
80Gray, D. "Oil Sands Conference Report". Mitretek. May 24, 2004.
81 Underground steam recovery requires about 3 bbls of water per barrel of recovered bitumen.
Mining operations need 4-6 bbls of water per bbl of bitumen. Ref.: Gray, D. Oil Sands
Conference Report. Mitretek. May 24, 2004.
petrochemicals production. 5 MM bpd would represent a five-fold increase from
current levels of production.82 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.83 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."84
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 2005.85
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.
n 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. 86
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.87
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-
82"Oil Sands Technology Roadmap". Alberta Chamber of Resources. January 2004.
83Stott, J. "CERI: Alberta Oil Sands Industry Outlook ‘Very Robust.’" OGJ. March 22, 2004.
84Jaremko, G. "Green forces rally to divert oil sands' use of Arctic gas. Gas use by 2015 could
surpass Mackenzie capacity". The Edmonton Journal. April 15, 2004.
85U.S. Department of Energy, Energy Information Administration, "Country Analysis Briefs –
Venezuela," June 2004.
86Gray, D. "Oil Sands Conference Report". Mitretek. May 24, 2004.
87Sen, C.T. "World’s LNG Industry Surges, Pushed By Confluence of Factors". June 14, 2004.
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-asusual
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 gasoline and other products.88
E. Liquid FueIs 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 now 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 the 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.89 The U.S. has huge coal reserves that are now being utilized for the
production of electricity; those resources could also provide feedstock for largescale
liquid fuel production.90 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.91
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 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
88Higgins,T. "Gas-To-Liquids: An Emerging Driver for Diesel Markets?" World Refining. April
89Kruger, P du P. "Startup Experience at Sasol’s Two and Three". Sasol. 1983.
90National Research Council. Fuels to Drive Our Future. National Academies Press. 1990.
91Gray, D. et al. "Coproduction of Ultra Clean Transportation Fuels, Hydrogen, and Electric Power
from Coal". Mitretek Systems Technical Report MTR 2001-43, July 2001.
92Johnson, H. et al. "Strategic Significance of America’s Oil Shale Resource". DOE. March
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.
n recent years, Shell has been developing a new shale oil recovery process that
uses insitu heating and avoids mining and massive materials handling. Little is
known about the process and its economics, so its potential cannot now be
evaluated.93 (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
economic. Reducing the cost of growing, harvesting, and converting biomass
crops will be necessary.94 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.
n 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.
93 O’Conner, T. "Mahogany Research Project: Technology to Secure Our Future". Presentation
at the DOE Shale Peer Review. February 19-20, 2004.
94 Smith, S.J. et al. "Near-Term US Biomass Potential." PNWD-3285. Battelle Memorial
Institute. January 2004.
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,95 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
t 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.”96 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.97 That study is the basis for the following
95American Association of Railroads. Railroad Facts. 2002.
96"DOE Hydrogen Posture Plan". www.eere.energy.gov/hydrogenandfuelcells. March 10, 2004.
97National Research Council. The Hydrogen Economy: Opportunities, Costs, Barriers and R & D
Needs. National Academies Press. 2004.
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.98
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.
. Factors That Can Cause Delay
t 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.99
Construction of even a single, relatively innocuous, urgently needed facility can
easily take more than a decade. For example, in 1999, King County,
98 Ibid.
99There has been extensive discussion of these problems in the literature; see, for example,
Management Information Services, Inc., Summary of the Implications of the Environmental
Justice Movement for EPRI and its Members; prepared for the Electric Power Research Institute,
1997; K.A Kilmer, G. Anandalingam, and J. Huber, “The Efficiency of Political Mechanisms for
Siting Nuisance Facilities: Are Opponents More Likely to Participate Than Supporters?” Journal
of Real Estate Finance and Economics, vol. 22, 2001; Sheila Foster, “Justice from the Ground
Up: Distributive Inequalities, Grassroots Resistance, and the Transformative Politics of the
Environmental Justice Movement,” California Law Review, vol. 86, no. 4 (1998), pp. 775-841; D.
Minehard and Z. Neeman, “Effective Siting of Waste Treatment Facilities,” Journal of
Environmental Economics and Management, vol. 43, 2002, pp. 303-324; Joanne Linnerooth-
Bayer, “Fair Strategies for Siting Hazardous Waste Facilities,” International Institute for Applied
Systems Analysis, Laxenburg, Austria, May 1999; Don Markley, “Its not NIMBY Anymore, its
BANANA,” Broadcast Engineering, March 1, 2002; S. Tierney and P. Hibbard, “Siting Power
Plants in the New Electric Industry Structure: Lessons From California," The Electric Journal,
2000, pp. 35-49; Dan Sandoval, “The NIMBY Challenge,” Recycling Today, April 14, 2003; Philip
Sittleburg, “NIMBY Mindset Looks for Zoning Loopholes,” Fire Chief, February 1, 2002.
Washington, initiated the siting process for the Brightwater wastewater treatment
plant, which it hopes to have operation in 2010.100
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.101 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.102
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
100Siting the Brightwater Treatment Facilities: Site Selection and Screening Activities, King
County, March 2001.
101U.S. Department of Energy, Environmental Siting Guide, Office of Energy Efficiency and
Renewable Energy, 2004.
102On the other hand, even in the midst of the energy crisis, the Alaska oil pipeline was approved
by only one vote in the U.S. Senate and, currently, EIA anticipates that an Alaska gas pipeline will
not be completed prior to 2020 – see U.S. Energy Information Administration, 2004 Annual
Energy Outlook, February, 2004.
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.103 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 dependant on foreign sources for substitute fuels derived
from U.S. coal.
103U.S. Department of Energy, Energy Information Administration, Monthly Energy Review, 2004.
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 2,400.104
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-1.105 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
Producers Consumers
Rank Country MM
Percent Rank Country MM
1 United States 9.0 11.7 1 United States 19.8 25.3
2 Saudi Arabia 8.7 11.3 2 Japan 5.3 6.8
3 Russia 7.7 10.0 3 China 5.2 6.6
4 Mexico 3.6 4.7 4 Germany 2.7 3.5
5 Iran 3.5 4.6 5 Russia 2.6 3.3
6 China 3.5 4.6 6 India 2.2 2.8
7 Norway 3.3 4.3 7 Korea, South 2.2 2.8
8 Canada 2.9 3.8 8 Brazil 2.2 2.8
9 Venezuela 2.9 3.8 9 Canada 2.1 2.7
10 United Kingdom 2.6 3.3 10 France 2.0 2.5
11 United Arab
2.4 3.1 11 Mexico 2.0 2.5
12 Nigeria 2.1 2.8 12 Italy 1.8 2.4
13 Iraq 2.0 2.7 13 United Kingdom 1.7 2.2
14 Kuwait 2.0 2.6 14 Saudi Arabia 1.5 1.9
15 Brazil 1.8 2.3 15 Spain 1.5 1.9
16 Algeria 1.6 2.0 16 Iran 1.3 1.7
17 Libya 1.4 1.8 17 Indonesia 1.1 1.4
18 Indonesia 1.4 1.8 18 Taiwan 0.9 1.2
19 Kazakhstan 0.9 1.2 19 Netherlands 0.9 1.1
20 Oman 0.9 1.2 20 Australia 0.9 1.1
103 other
12.6 16.3 194 other
104U.S. Department of Energy, Energy Information Administration. "Table 1.2 World Petroleum
Consumption, 1980-2002" database and "Table G.2 World Production of Crude Oil, NGPL, Other
Liquids, and Refinery Processing Gain 1980-2002" database, 2004.
105 Ibid
A. Introduction
ssues 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
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.106
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. Our wedge
pattern is shown in Figure VIII-1, where the horizontal axis is time and the vertical
axis is market impact, measured in barrels per day of savings or production. The
figure is bounded on the right side for illustrative purposes only. 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.
Figure VIII-1. Delayed wedge approximation for various mitigation options
How our delayed wedges approximate reality is illustrated in Figure VIII-2, which
shows possible fuel savings associated with implementation of significant new
Corporate Average Fuel Efficiency (CAFE) standards.107
106 Pacala, S., Socolow, R. "Stabilization Wedges: Solving the Climate Problem for the Next 50
Years with Current Technologies.” Science. August 13, 2004.
107 These potential savings are documented in National Research Council, National Academy of
Sciences, Effectiveness and Impact of Corporate Average Fuel Economy (CAFE) Standards,
Washington, D.C.: National Academy Press, 2002; Management Information Services, Inc., and
20/20 Vision, Fuel Standards and Jobs: Economic, Employment, Energy, and Environmental
Impacts of Increased CAFE Standards Through 2020, report prepared for the Energy Foundation,
San Francisco, California, July 2002; David L. Greene and John DeCicco, Engineering-Economic
Analysis of Automotive Fuel Economy Potential in the United States, paper presented at the IEA
International Workshop on Technologies to Reduce Greenhouse Gas Emissions, Washington,
D.C., May 1999; David Friedman, et al, Drilling in Detroit: Tapping Automaker Ingenuity to Build
Safe and Efficient Automobiles, Union of Concerned Scientists, UCS Publications, Cambridge,
MA, June 2001; Roland Hwang, Bryanna Millis, and Theo Spencer, Clean Getaway: Toward
Safe and Efficient Vehicles, Natural Resources Defense Council: New York, July 2001; Brent D.
Yacobucci, Marc Ross, Technical Options for Improving the Fuel Economy of U.S. Cars and Light
Prepare Implement
Barrels/ Day
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
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
Trucks by 2010-2015, American Council for an Energy Efficient Economy, July 2001; Robert L
Bamberger, Automobile and Light Truck Fuel Economy: Is CAFE Up to Standards? Washington,
D.C.: Congressional Research Service, September 29, 2001; Energy and Environmental
Analysis, Inc. Technology and Cost of Future Fuel Economy Improvements for Light-Duty
Vehicles, prepared for the National Research Council, 2001.
Figure VII-2. The delayed wedge approximation in the case of
major changes in transportation fuel consumption
0 10 20 30
Time - Years
Actual Fuel Savings
$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.108
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
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 & 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.
n 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 automobile 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.109
108 The choice of a minimum is subjective. A minimum of 50 percent seems reasonable, but a
higher rate is clearly more desirable.
109 While diesel engines offer significant improvements in fuel economy over gasoline engines,
their benefits are notably less than hybrids. For simplicity, we neglect the broader use of diesels
in this study, which is not meant to imply that they might indeed make an important contribution in
the LDV markets.
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
1. Enhanced Oil Recovery is applicable worldwide.
2. Heavy oil / Oil 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
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.110
Over 45% 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
110 In their recently published hydrogen study, the National Research Council has shown that
hydrogen from biomass is roughly three times as expensive as coal-based hydrogen. This
relationship holds roughly for liquids production, another basis for not considering biomass fuels
as acceptable under our criteria. See National Research Council, National Academy of Sciences,
The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs, Washington, D.C.:
National Academy Press, 2004
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.
t 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(s), 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
t 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 starting point is the triangular pattern of production increase followed by
production decline shown in Figure II-2. 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 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
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.”111 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
111 "Hydrocarbon Resources: Future Supply and Demand." World Energy Council - 18 th
Congress, Buenos Aires, October 2001.
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.112 It should
be noted that other analysts have projected decline rates of 3-8%, which would
make the mitigation problem much more difficult.113
H. Our Wedges
n Appendix IV we develop the sizes of the wedges that we believe appropriate
for our trends analysis. The categories, delays and 10-year estimated impacts
are shown in Figure VIII-3. Once again, bear in mind that these are rough
approximations aimed at illustrating the inherently large scale of mitigation.
Figure VIII-3. Assumed wedges
112 Compounding starts at 67.3 MM bpd at –20 years, rises to 100 MM bpd at year 0, and drops
to 66.8 MM bpd at +20 years.
113 See for instance Al-Husseini, S.I. , Retired Exec. V.P., Saudi Aramco. A Producer’s
Perspective on the Oil Industry. Oil and Money Conference. London. October 26, 2004;
Hakes, J. Long Term World Oil Supply. EIA. April 18, 2000; and ExxonMobil. A Report on
Energy Trends, Greenhouse Emissions and Alternate Energy. February 2004.
0 5 10 15
Years After Crash Program Initiation
(MM bpd)
Coal Liquids
Heavy Oil
Eff. Vehicles
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 as
shown in Figures VIII-4, 5 and 6.
-20 -10 0 +10 +20
(MM bpd)
Supply = Demand
Supply Shortfall
Figure VIII-4. Mitigation crash programs started at the time of world
oil peaking: A significant supply shortfall occurs over the forecast
Figure VIII-5. Mitigation crash programs started 10 years before world oil
peaking: A moderate supply shortfall occurs after roughly 10 years.
Figure VIII-6. Mitigation crash programs started 20 years before world oil
peaking: No supply shortfall occurs during the forecast period.
-20 -10 0 +10 +20
(MM bpd)
Supply Shortfall
Delayed Oil
-20 -10 0 +10 +20
(MM bpd)
J. Observations & 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
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
• 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
t 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
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
Oil prices have traditionally been volatile. Causes include political events,
weather, labor strikes, infrastructure problems, and fears of terrorism.114 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.115
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
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.117
114Over the past 20 years, oil prices have been extremely volatile. Between 1982 and 2002, the
standard deviation in monthly oil prices was 29.5 percent of its mean. The only other major
commodity whose price exhibited similar volatility was coffee – 27.8 percent of its mean. See
Andre Plourde and G.C. Watkins, “Crude Oil Prices Between 1985 and 1994: How Volatile in
Relation to Other Commodities?” Resource and Energy Economics, Vol. 20, 1998, pp. 245-262.
In general, Plourde and Watkins found that oil prices fluctuated more or at least as much as the
most volatile of commodity prices; see the discussion in Hillard Huntington, “Energy Disruptions,
Interfirm Price Effects, and the Aggregate Economy,” Stanford Energy Modeling Forum,
September 2002.
115International Energy Agency, “IEA Expresses Concern About High Oil Prices as it Celebrates
its 30th Anniversary,” Istanbul, April 2004; International Monetary Fund, World Economic Outlook
Report, September 2003.
116Walter C. Labys, Globalization, Oil Price Volatility, and the U.S. Economy, 2001.
117Vincente Ramirez, “Oil Crises Delay – a World Oil Price Forecast,” REXplore Zachasumsc,
Switzerland, July 1999.
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.118 As world oil peaking is approached, it is not difficult to imagine
that the terrorism premium could increase even more.
n 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.119
118John Schoen, “Oil Prices Include a Growing Risk Premium," Business with MSNBC, Oil and
Energy News, May 12, 2004.
119Jean-Marie Bourdaire, “Energy Supply Conditions and Oil Price Regime,” presented at the
Association for the Study of Peak Oil, Paris, May 2003.
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
• 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
• 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
• 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.
• Large-scale, sustained Middle East political instability hinders oil
• 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.
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
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
8. Government Intervention Will be Required
ntervention 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
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.
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.
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
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).120 We believe the most likely of
the EIA scenarios is the one based on the USGS expected ultimate world
recoverable oil of 3,003 billion barrels coupled with a 2% annual world oil
demand escalation.
Figure A-I shows the two EIA scenarios based on these assumptions. 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 in Figure II-2. 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.
t 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.121 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.
120 DOE EIA. "Long Term World Oil Supply." April 18, 2000.
121 Deffeyes, K.S. Hubbert’s Peak-The Impending World Oil Shortage. Princeton University
Press. 2003. p. 134.
Figure A-1. Two EIA oil production scenarios based on expected ultimate
world-recoverable oil of 3,003 billion barrels and a 2 percent annual world
oil demand escalation
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.122 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.123
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.124
Nevertheless, except for several serious disruptions (and then only temporarily),
oil prices have risen little in real terms over the past century, as shown in Figure
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
122This consensus emerged by the 1990s; see, for example, K. Lee, S. Ni, and R. Ratti, “Oil
Shocks and the Macroeconomy: The Role of Price Variability," Energy Journal, Vol. 16, no. 4,
123Once again, this experience may preclude such an option in the future, even though it may be
called for. For example, by the 1990s, CBO had concluded that the threat posed by oil
disruptions had declined; see U.S. Congressional Budget Office, op. cit.
124Estimates range from $2 trillion to more than $7 trillion (2004 dollars) -- exclusive of military or
political costs. See U.S. General Accounting Office, Energy Security: Evaluating U.S.
Vulnerability To Oil Supply Disruptions and Options for Mitigating Their Effects, GAO/RCED-97-6,
1997; David Greene and Nataliya Tishchishyna, Cost of Oil Dependence: A 2000 Update, Oak
Ridge National Laboratory, May 2000; National Defense Council Foundation, The Hidden Cost of
Imported Oil, October 2003.
Figure A-2. Oil Prices in Current and Constant Dollars: 1900 - 2004
economy, and these complicate monetary policies designed to counter the
inflationary effects of the disruption.125
The U.S. is currently less oil-dependent (in terms of oil / GDP ratios) than during
the 1970s. However, as shown in Figure A-3, 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.126 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. As shown in
Figure A-2, 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
exceed $3 per gallon to equal real 1981 prices. Even then, however, energy
would still be 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 expenditures127.
125 See the discussion in Roger Bezdek and John Taylor, “Allocating Petroleum Products During
Oil Supply Disruptions,” Science, June 19, 1981, Vol. 212, pp. 1357-1363.
126 DOE, EIA Monthly Energy Review and Management Information Services, Inc., 2004
127In 1981, consumers spent nearly six percent of their incomes on gasoline, but in 2003 they
spent only three percent of their incomes on gasoline; in 1985, gasoline and oil represented 20
percent of the cost of owning and operating a vehicle, but by 2002 represented only 10 percent of
the cost.
dollars per barrel
real '03 dollars nominal dollars
Nevertheless, over the past 20 years, oil prices have been extremely volatile –
more volatile than virtually any other commodity.128
Figure A-3. U.S. Oil Imports and Transportation Shares of Oil Consumption, 1973
and 2003
128Between 1982 and 2002, the standard deviation in monthly oil prices was 29.5 percent of its
mean, and the only other major commodity whose price exhibited similar volatility was coffee –
27.8 percent of its mean. See Andre Plourde and G.C. Watkins, “Crude Oil Prices Between 1985
and 1994: How Volatile in Relation to Other Commodities?” Resource and Energy Economics,
Vol. 20, 1998, pp. 245-262. In general, Plourde and Watkins found that oil prices fluctuated more
or at least much as the most volatile of commodity prices; see the discussion in Hillard
Huntington, “Energy Disruptions, Interfirm Price Effects, and the Aggregate Economy,” Stanford
Energy Modeling Forum, September 2002.
net imports transportation
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. As shown in Figure A-4,
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
Figure A-4. World Petroleum Consumption, 1960-2025
Energy forecasting is difficult due to the numerous complex factors that influence
energy supply and demand.130 Here we utilize the U.S. Energy Department's
Energy Information Administration forecasts of future world oil requirements.
129 DOE EIA, International Energy Outlook, 2004.
130 See the discussion in Roger H. Bezdek and Robert M. Wendling, "A Half-Century of Long-
Range Energy Forecasts; Errors Made, Lessons Learned, and Implications for Forecasting,"
1960 1970 1980 1990 2000 2010 2020 2025
million barrels per day
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 % change)131
Petroleum GDP
Consumption (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
131 Source: U.S. Department of Energy, Energy Information Administration, 2004.
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
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.133 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 Sciences134) is likely to actually reduce total U.S. gasoline
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.135 We
132Management Information Services, Inc., and 20/20 Vision, Fuel Standards and Jobs:
Economic, Employment, Energy, and Environmental Impacts of Increased CAFE Standards
Through 2020, report prepared for the Energy Foundation, San Francisco, California, July 2002.
134National Research Council, National Academy of Sciences, Effectiveness and Impact of
Corporate Average Fuel Economy (CAFE) Standards, Washington, D.C.: National Academy
Press, 2002.
135Ibid. Management Information Services, Inc., and 20/20 Vision, op. cit.; David L. Greene and
John DeCicco, Engineering-Economic Analysis of Automotive Fuel Economy Potential in the
United States, paper presented at the IEA International Workshop on Technologies to Reduce
Greenhouse Gas Emissions, Washington, D.C., May 1999; David Friedman, et al, Drilling in
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.136
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
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.137 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. Our world
Detroit: Tapping Automaker Ingenuity to Build Safe and Efficient Automobiles, Union of
Concerned Scientists, UCS Publications, Cambridge, MA, June 2001; Roland Hwang, Bryanna
Millis, and Theo Spencer, Clean Getaway: Toward Safe and Efficient Vehicles, Natural
Resources Defense Council: New York, July 2001; Brent D. Yacobucci, Sport Utility Vehicles,
Mini-Vans and Light Trucks: An Overview of Fuel Economy and Emissions Standards,
Congressional Research Service, U.S. Congress: Washington, D.C., (RS20298), January 16,
2001; Robert L Bamberger, Automobile and Light Truck Fuel Economy: Is CAFE Up to
Standards? Washington, D.C.: Congressional Research Service, September 29, 2001; Energy
and Environmental Analysis, Inc. Technology and Cost of Future Fuel Economy Improvements
for Light-Duty Vehicles, prepared for the National Research Council, 2001.
136See Management Information Services, Inc., and 20/20 Vision, op. cit.; Roger H. Bezdek and
Robert M. Wendling, “The Economic and Employment Effects of Increasing CAFE Standards.”
Energy Policy, 2004.
137U.S. Energy Information Administration, World Petroleum Consumption by Fuel database,
2003, and Oak Ridge National Laboratory, Transportation Energy Data Book, 2003. Japan has
10% of total vehicle registrations, Germany 9 percent, France 5 percent, and UK 5 percent,
totaling (including the U.S.) 54 percent%. However, the U.S. has a higher miles per vehicle rate
than any other developed country – it is less densely populated, has relatively inexpensive
gasoline, and U.S. drivers do a large amount of discretionary driving.
vehicle fuel efficiency wedge is assumed to be as follows:
Time - Years
We note that a detailed study of these issues and opportunities would be of great
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 gasificationbased
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
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
138 Kruger, P du P. "Startup Experience at Sasol’s Two and Three." Sasol. 1983.
139 Collings, J. "Mind Over Matter – The Sasol Story: A Half-Century of Technological
Innovation," Sasol. 2002.
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.140 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 plans in China.141
f 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 counties might become the
sites of many coal liquefaction plants using imported coal, possibly even from the
Our coal liquefaction wedge then appears be as follows:
140 DOE EIA. International Energy Outlook. 2004.
141 "Sasol Taps Into China’s Demand for Oil." Financial Times. July 8, 2004.
Time – Years
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.142 Such
reserves could support a massive expansion in production of these
unconventional oils.
n 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:143
• “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.”
142 Williams, B. "Heavy Hydrocarbons Playing Key Role in Peak Oil Debate, Future Supply."
OGJ. July 28, 2003; DOE EIA. Early Release AEO 2004. December 16, 2003.
143 "Drivers of the Energy Scene." World Energy Council. December 2003.
• “(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.”
n line with the WEC, we assume the following for our Venezuelan Heavy Oils
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
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
3. aWe know of no upper limit on Canadian oil sands production, so for
purposes of this order-of-magnitude illustration, we do not assume one.
ur heavy oil wedge therefore is approximated as follows:
Time - Years
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.144 We translate
144Even under a crash program, 5 percent production increase in 10 years does not seem
achievable, but roughly half that level might be possible. Our reasoning is strongly influenced by
the need for relatively pure CO2, which is difficult to obtain in most places around the world. This
the 3 percent to 3 MM bpd, based on our assumed world oil peaking level of
roughly 100 MM bpd. Our EOR wedge thus appears as follows:
Time - Years
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 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.145
is especially true in the Middle East, where large sources of relatively pure CO2 are somewhat
rare at this time.
145 McCaughey, J. "Is Gas OPEC in the Cards?" Electricity Daily. June 29, 2004.
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.
The resultant wedge might then be as follows:
Time - 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
(Years) (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
Ordering the various contributions by their starting dates, the total mitigation
wedge is as shown in Figure A-5.
Figure A-5. The total of the wedge estimates
0 5 10 15
Years After Crash Program Initiation
(MM bpd)
Coal Liquids
Heavy Oil
Eff. Vehicles
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 2020.146 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.147 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
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
146 US DOE ONPOSR. Strategic Significance of America’s Oil Shale, Vols I and II. March 2004.
147 Rocky Mountain News, October 18, 2004, “Shale’s New Hope: Shell Tests Technology to
Cook Oil out of Rocks Underground,” p. 1B.
ceased operation before the implementation of the 1990 Clean Air Act
amendments, new emission-control equipment would need to be tested on US
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,148 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,149 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.
148 NREL 2002.
149 USDA 2002.
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
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
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.
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
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.