PEAKING OF WORLD OIL PRODUCTION:
IMPACTS, MITIGATION, & RISK MANAGEMENT

Robert L. Hirsch, SAIC, Project Leader
Roger Bezdek, MISI
Robert Wendling, MISI
February 2005

DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process 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.

TABLE OF CONTENTS

EXECUTIVE SUMMARY
I.	INTRODUCTION
II.	PEAKING OF WORLD OIL PRODUCTION
III.	WHY TRANSITION WILL BE TIME CONSUMING
IV.	LESSONS FROM PAST EXPERIENCE
V.	LEARNING FROM NATURAL GAS
VI.	MITIGATION OPTIONS & ISSUES Conservation Improved Oil Recovery Heavy Oil and Oil Sands Gas-To-Liquids Liquids from U.S Domestic Sources Fuel Switching to Electricity Other Fuel Switching Hydrogen Factors That Can Cause Delay
VII.	A WORLD PROBLEM
VIII.	THREE SCENARIOS
IX.	MARKET SIGNALS AS PEAKING IS APPROACHED
X.	WILD CARDS
XI.	SUMMARY AND CONCLUDING REMARKS
APPENDICES

EXECUTIVE SUMMARY

The peaking of world oil production presents the U.S. and the world with an unprecedented risk management problem. As peaking is approached, liquid fuel prices and price volatility will increase dramatically, and, without timely mitigation, the economic, social, and political costs will be unprecedented. Viable mitigation options exist on both the supply and demand sides, but to have substantial impact, they must be initiated more than a decade in advance of peaking.

In 2003, the world consumed just under 80 million barrels per day (MM bpd) of oil. U.S. consumption was almost 20 MM bpd, two-thirds of which was in the transportation sector. The U.S. has a fleet of about 210 million automobiles and light trucks (vans, pick-ups, and SUVs). The average age of U.S. automobiles is nine years. Under normal conditions, replacement of only half the automobile fleet will require 10-15 years. The average age of light trucks is seven years. Under normal conditions, replacement of one-half of the stock of light trucks will require 9-14 years. While significant improvements in fuel efficiency are possible in automobiles and light trucks, any affordable approach to upgrading will be inherently time-consuming, requiring more than a decade to achieve significant overall fuel efficiency improvement.

Besides further oil exploration, there are commercial options for increasing world oil supply and for the production of substitute liquid fuels: 1) Improved Oil Recovery (IOR) can marginally increase production from existing reservoirs; one of the largest of the IOR opportunities is Enhanced Oil Recovery (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 worldís abundant coal reserves; and finally, 4) Clean substitute fuels can be produced from remotely located natural gas, but exploitation must compete with the worldís growing demand for liquefied natural gas. However, world-scale contributions from these options will require 10-20 years of accelerated effort.

Dealing with world oil production peaking will be extremely complex, involve literally trillions of dollars and require many years of intense effort. To explore these complexities, three alternative mitigation scenarios were analyzed:

• Scenario I assumed that action is not initiated until peaking occurs.
• Scenario II assumed that action is initiated 10 years before peaking.
• Scenario III assumed action is initiated 20 years before peaking.

For this analysis estimates of the possible contributions of each mitigation option were developed, based on an assumed crash program rate of implementation.

Our approach was simplified in order to provide transparency and promote understanding. Our estimates are approximate, but the mitigation envelope that results is believed to be directionally indicative of the realities of such an enormous undertaking. The inescapable conclusion is that more than a decade will be required for the collective contributions to produce results that significantly impact world supply and demand for liquid fuels.

Important observations and conclusions from this study are as follows:

1. When world oil peaking will occur is not known with certainty. A fundamental problem in predicting oil peaking is the poor quality of and possible political biases in world oil reserves data. Some experts believe peaking may occur soon. This study indicates that “soon” is within 20 years.
2. The problems associated with world oil production peaking will not be temporary, and past “energy crisis” experience will provide relatively little guidance. The challenge of oil peaking deserves immediate, serious attention, if risks are to be fully understood and mitigation begun on a timely basis.
3. Oil peaking will create a severe liquid fuels problem for the transportation sector, not an “energy crisis” in the usual sense that term has been used.
4. Peaking will result in dramatically higher oil prices, which will cause protracted economic hardship in the United States and the world. However, the problems are not insoluble. Timely, aggressive mitigation initiatives addressing both the supply and the demand sides of the issue will be required.
5. In the developed nations, the problems will be especially serious. In the developing nations peaking problems have the potential to be much worse.
6. Mitigation will require a minimum of a decade of intense, expensive effort, because the scale of liquid fuels mitigation is inherently extremely large.
7. While greater end-use efficiency is essential, increased efficiency alone will be neither sufficient nor timely enough to solve the problem. Production of large amounts of substitute liquid fuels will be required. A number of commercial or near-commercial substitute fuel production technologies are currently available for deployment, so the production of vast amounts of substitute liquid fuels is feasible with existing technology.
8. Intervention by governments will be required, because the economic and social implications of oil peaking would otherwise be chaotic. The experiences of the 1970s and 1980s offer important guides as to government actions that are desirable and those that are undesirable, but the process will not be easy.

Mitigating the peaking of world conventional oil production presents a classic risk management problem:

• Mitigation initiated earlier than required may turn out to be premature, if peaking is long delayed.
• If peaking is imminent, failure to initiate timely mitigation could be extremely damaging.

Prudent risk management requires the planning and implementation of mitigation well before peaking. Early mitigation will almost certainly be less expensive than delayed mitigation. A unique aspect of the world oil peaking problem is that its timing is uncertain, because of inadequate and potentially biased reserves data from elsewhere around the world. In addition, the onset of peaking may be obscured by the volatile nature of oil prices. Since the potential economic impact of peaking is immense and the uncertainties relating to all facets of the problem are large, detailed quantitative studies to address the uncertainties and to explore mitigation strategies are a critical need.

The purpose of this analysis was to identify the critical issues surrounding the occurrence and mitigation of world oil production peaking. We simplified many of the complexities in an effort to provide a transparent analysis. Nevertheless, our study is neither simple nor brief. We recognize that when oil prices escalate dramatically, there will be demand and economic impacts that will alter our simplified assumptions. Consideration of those feedbacks will be a daunting task but one that should be undertaken.

Our study required that we make a number of assumptions and estimates. We well recognize that in-depth analyses may yield different numbers. Nevertheless, this analysis clearly demonstrates that the key to mitigation of world oil production peaking will be the construction 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.

In summary, the problem of the peaking of world conventional oil production is unlike any yet faced by modern industrial society. The challenges and uncertainties need to be much better understood. Technologies exist to mitigate the problem. Timely, aggressive risk management will be essential.

I. INTRODUCTION

Oil is the lifeblood of modern civilization. It fuels the vast majority of the worldís 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 earthís 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.

Our aim in this study is to

• Summarize the difficulties of oil production forecasting;
• Identify the fundamentals that show why world oil production peaking is such a unique challenge;
• Show why mitigation will take a decade or more of intense effort;
• Examine the potential economic effects of oil peaking;
• Describe what might be accomplished under three example mitigation scenarios.
• Stimulate serious discussion of the problem, suggest more definitive studies, and engender interest in timely action to mitigate its impacts.

In Chapter II we describe the basics of oil production, the meaning of world conventional oil production peaking, the challenge of making accurate forecasts, and the effects that higher prices and advanced technology might have on oil production.

Because of the massive scale of oil use around the world, mitigation of oil shortages will be difficult, time consuming, and expensive. In Chapter III we describe the extensive and critical uses of U.S. oil and the long economic and mechanical lifetimes of existing liquid fuel consuming vehicles and equipment.

While it is impossible to predict the impact of world oil production peaking with any certainty, much can be learned from past oil disruptions, particularly the 1973 oil embargo and the 1979 Iranian oil shortage, as discussed in Chapter IV. In Chapter V we describe the developing shortages of U.S. natural gas, shortages that are occurring in spite of assurances of abundant supply provided just a few years ago. The parallels to world oil supply are disconcerting.

In Chapter VI we describe available mitigation options and related implementation issues. We limit our considerations to technologies that are near ready or currently commercially available for immediate deployment. Clearly, accelerated research and development holds promise for other options. However, the challenge related to extensive near-term oil shortages will require deployment of currently viable technologies, which is our focus.

Oil is a commodity found in over 90 countries, consumed in all countries, and traded on world markets. To illustrate and bracket the range of mitigation options, we developed three illustrative scenarios. Two assume action well in advance of the onset of world oil peaking — in one case, 20 years before peaking and in another case, 10 years in advance. Our third scenario assumes that no action is taken prior to the onset of peaking. Our findings illustrate the magnitude of the problem and the importance of prudent risk management.

Finally, we touch on possible market signals that might foretell the onset of peaking and possible wildcards that might change the timing of world conventional oil production peaking. In conclusion, we frame the challenge of an unknown date for peaking, its potentially extensive economic impacts, and available mitigation options as a matter of risk management and prudent response. The reader is asked to contemplate three major questions:

• What are the risks of heavy reliance on optimistic world oil production peaking projections?
• Must we wait for the onset of oil shortages before actions are taken?
• What can be done to ensure that prudent mitigation is initiated on a timely basis?

II. PEAKING OF WORLD OIL PRODUCTION [3]

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 earthís 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 reservoirís maximum oil production rate, which typically occurs after roughly half of the recoverable oil in a reservoir has been produced. In many ways, what is likely to happen on a world scale is similar to what happens to individual reservoirs, because world production is the sum total of production from many different reservoirs.

Because oil is usually found thousands of feet below the surface and because oil reservoirs normally do not have an obvious surface signature, oil is very difficult to find. Advancing technology has greatly improved the discovery process and reduced exploration failures. Nevertheless, oil exploration is still inexact and expensive.

Once oil has been discovered via an exploratory well, full-scale production requires many more wells across the reservoir to provide multiple paths that facilitate the flow of oil to the surface. This multitude of wells also helps to define the total recoverable oil in a reservoir — its so-called “reserves.”

B. Oil Reserves

The concept of reserves is generally not well understood. “Reserves” is an estimate of the amount of oil in a reservoir that can be extracted at an assumed cost. Thus, a higher oil price outlook often means that more oil can be produced, but geology places an upper limit on price-dependent reserves growth; in well managed oil fields, it is often 10-20 percent more than what is available at lower prices.

Reserves estimates are revised periodically as a reservoir is developed and new information provides a basis for refinement. Reserves estimation is a matter of gauging how much extractable oil resides in complex rock formations that exist typically one to three miles below the surface of the ground, using inherently limited information. Reserves estimation is a bit like a blindfolded person trying to judge what the whole elephant looks like from touching it in just a few places. It is not like counting cars in a parking lot, where all the cars are in full view.

Specialists who estimate reserves use an array of methodologies and a great deal of judgment. Thus, different estimators might calculate different reserves from the same data. Sometimes politics or self-interest influences reserves estimates, e.g., an oil reservoir owner may want a higher estimate in order to attract outside investment or to influence other producers.

Reserves and production should not be confused. Reserves estimates are but one factor in estimating future oil production from a given reservoir. Other factors include production history, understanding of local geology, available technology, oil prices, etc. An oil field can have large estimated reserves, but if the field is past its maximum production, the remaining reserves will be produced at a declining rate. This concept is important because satisfying increasing oil demand not only requires continuing to produce older oil reservoirs with their declining production, it also requires 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.

The peaking of world oil production has been a matter of speculation from the beginning of the modern oil era in the mid 1800s. In the early days, little was known about petroleum geology, so predictions of peaking were no more than guesses without basis. Over time, geological understanding improved dramatically and guessing gave way to more informed projections, although the knowledge base involves numerous uncertainties even today.

Past predictions typically fixed peaking in the succeeding 10-20 year period. Most such predictions were wrong, which does not negate that peaking will someday occur. Obviously, we cannot know if recent forecasts are wrong until predicted dates of peaking pass without incident.

With a history of failed forecasts, why revisit the issue now? The reasons are as follows:

1. Extensive drilling for oil and gas has provided a massive worldwide database; current geological knowledge is much more extensive than in years past, i.e., we have the knowledge to make much better estimates than previously.
2. Seismic and other exploration technologies have advanced dramatically in recent decades, greatly improving our ability to discover new oil reservoirs. Nevertheless, the oil reserves discovered per exploratory well began dropping worldwide over a decade ago. We are finding less and less oil in spite of vigorous efforts, suggesting that nature may not have much more to provide.
3. Many credible analysts have recently become much more pessimistic about the possibility of finding the huge new reserves needed to meet growing world demand.
4. Even the most optimistic forecasts suggest that world oil peaking will occur in less than 25 years.
5. The peaking of world oil production could create enormous economic disruption, as only glimpsed during the 1973 oil embargo and the 1979 Iranian oil cut-off.

Accordingly, there are compelling reasons for in-depth, unbiased reconsideration.

D. Types of Oil

Oil is classified as “Conventional” and “Unconventional.” Conventional oil is typically the highest quality, lightest oil, which flows from underground reservoirs with comparative ease. Unconventional oils are heavy, often tar-like. They are not readily recovered since production typically requires a great deal of capital investment and supplemental energy in various forms. For that reason, most current world oil production is conventional oil. [5] (Unconventional oil production will be discussed in Chapter VI).

E. Oil Resources [6]

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 reservoirs.

Because oil prices have been relatively high for the past decade, oil companies have conducted extensive exploration over that period, but their results have been disappointing. If recent trends hold, there is little reason to expect that exploration success will dramatically improve in the future. This situation is evident in Figure 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 production.

F. Impact of Higher Prices and New Technology

Conventional oil has been the mainstay of modern civilization for more than a century, because it is most easily brought to the surface from deep underground reservoirs, and it is the most easily refined into finished fuels. The U.S. was endowed with huge reserves of petroleum, which underpinned U.S. economic growth in the early and mid twentieth century. However, U.S. oil resources, like those in the world, are finite, and growing U.S. demand resulted in the peaking of U.S. oil production in the Lower 48 states in the early 1970s. With relatively minor exceptions, U.S. Lower 48 oil production has been in continuing decline ever since. Because U.S. demand for petroleum products continued to increase, the U.S. became an oil importer. Today, the U.S. depends on foreign sources for almost 60 percent of its needs, and future U.S. imports are projected to rise to 70 percent of demand by 2025. [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. Todayís technology allows oil reservoirs to be more readily discovered and better understood sooner than heretofore. Accordingly, reservoirs can be produced more rapidly, which provides significant economic advantages to the operators but also hastens peaking and depletion.

Some economists expect higher oil prices and improved technologies to continue to provide ever-increasing oil production for the foreseeable future. Most geologists disagree because they do not believe that there are many huge new oil reservoirs left to be found. Accordingly, geologists and other observers believe that supply will eventually fall short of growing world demand — and result in the peaking of world conventional oil production.

To gain some insight into the effects of higher oil prices and improved technology on oil production, let us briefly examine related impacts in the U.S. Lower 48 states. This region is a useful surrogate for the world, because it was one of the worldís 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.

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 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]

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 worldís then existing producing oil reservoirs, which will be in various stages of development, and 2) all the yet-to-be discovered reservoirs in their various states of development. This is an extremely complex summation problem, because of the variability and possible biases in publicly available data. In practice, estimators use various approximations to predict future world oil production. The remarkable complexity of the problem can easily lead to incorrect conclusions, either positive or negative.

Various individuals and groups have used available information and geological estimates to develop projections for when world oil production might peak. A sampling of recent projections is shown in Table II-1.

III. WHY THE TRANSITION WILL BE SO TIME CONSUMING

A. Introduction

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

B. Historical U.S. Oil Consumption Patterns

After the two oil price shocks and supply disruptions in 1973-74 and 1979, oil consumption in the U.S. decreased 13 percent, declining from nearly 35 quads in 1973 to 30 quads in 1983. However, overall consumption continued to grow after the 1983 low and has continuously increased over the last 20 years, reaching over 39 quads in 2003, as shown in Figure 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 sectorís share of total U.S. consumption remained between 24 and 26 percent. In sharp contrast to all other sectors, U.S. oil consumption for transportation purposes has increased steadily every year, rising from just over 17 quads in 1973 to 26 quads in 2003. By 2003, the transportation sector accounted for two-thirds of the oil consumed in the U.S.

C. Petroleum in the Current U.S. Economy

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

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.

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]

A similar situation exists with light trucks (vans, pick-ups, and SUVs), which consume 3.6 MM bpd of oil, accounting for 18 percent of total oil consumption. Light trucks are depreciated on a faster schedule, and their financial-based current-cost average age is 2.9 years. However, the average physical age of the rolling stock is seven years, and the median lifetime of light trucks is 16 years. At current replacement rates, one-half of the 80-million light trucks will be replaced in the next 9-14 years at a cost of $1 trillion.

Seven million heavy trucks (including buses, highway trucks, and off-highway trucks) represent the third largest consumer of oil at 3.0 MM bpd, 16 percent of total consumption. The current-cost average age of heavy trucks is 5.0 years, but the median lifetime of this equipment is 28 years. The disparity in the average age and the median lifetime estimates indicate that a significant number of vehicles are 40-60 years old. At normal replacement levels, one-half of the heavy truck stock will be replaced by businesses in the next 15-20 years at a cost of $1.5 trillion.

The fourth-largest consumer of oil is the airlines, which consume the equivalent of 1.1 MM bpd, representing six percent of U.S. consumption. The 8,500 aircraft have a current-cost average age of 9.1 years, and a median lifetime of 22 years. Airline deregulation and the events of September 11, 2001, 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]

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.

IV. LESSONS AND IMPLICATIONS FROM PREVIOUS SUPPLY DISRUPTIONS

A. Previous Oil Supply Shortfall and Disruptions

There have been over a dozen global oil supply disruptions [34] over the past half-century, as summarized in Figure IV-1.

Briefly,

• Disruptions ranged in duration from one to 44 months. Supply shortfalls were 0.3-4.6 MM bpd, and eight resulted in average gross supply shortfalls of at least 2 MM bpd.
• Percentage supply shortfalls varied from roughly one percent to nearly 14 percent of world production.
• The most traumatic disruption, 1973-74, was not the most severe, but it nevertheless lead to greatly increased oil prices and significant worldwide economic damage.
• The second most traumatic disruption, 1979, was also neither the longest nor the most severe.

For purposes of this study, the 1973-74 and 1979 disruptions are taken as the most relevant, because they are believed to offer the best insights into what 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 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:

• 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 price. [41]
• The loss resulting from the 1979 oil disruption was about42 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.
• 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 countries.

F. Implications

1. The World Economy

A shortfall of oil supplies caused by world conventional oil production peaking will sharply increase oil prices and oil price volatility. As oil peaking is approached, relatively minor events will likely have more pronounced impacts on oil prices and futures markets.

Oil prices remain a key determinant of global economic performance, and world economic growth over the past 50 years has been negatively impacted in the wake of increased oil prices. The greater the supply shortfall, the higher the price increases; the longer the shortfall, the greater will be the adverse economic affects.

The long-run impact of sustained, significantly increased oil prices associated with oil peaking will be severe. Virtually certain are increases in inflation and unemployment, declines in the output of goods and services, and a degradation of living standards. Without timely mitigation, the long-run impact on the developed economies will almost certainly be extremely damaging, while many developing nations will likely be even worse off. [44]

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.

If the shortfall persisted or worsened (as is likely in the case of peaking), the economic impacts would be much greater. Oil supply disruptions over the past three decades have cost the U.S. economy about $4 trillion, so supply shortfalls associated with the approach of peaking could cost the U.S. as much as all of the oil supply disruptions since the early 1970s combined.

The effects of oil shortages on the U.S. are also likely to be asymmetric. Oil supply disruptions and oil price increases reduce economic activity, but oil price declines have a less beneficial impact. [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, inter-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]

V. LEARNING FROM THE NATURAL GAS EXPERIENCE

A. Introduction

A dramatic example of the risks of over-reliance on geological resource projections is the experience with North American natural gas. Natural gas supplies roughly 20 percent of U.S. energy demand. It has been plentiful at real prices of roughly $2/Mcf for almost two decades. Over the past 10 years, natural gas has become the fuel of choice for new electric power generation plants and, at present, virtually all new electric power generation plants use natural gas.

Part of the attractiveness of natural gas was resource estimates for the U.S. and Canada that promised growing supply at reasonable prices for the foreseeable future. That optimism turns out to have been misplaced, and the U.S. is now experiencing supply constraints and high natural gas prices. Supply difficulties are almost certain for at least the remainder of the decade. The North American natural gas situation provides some useful lessons relevant to the peaking of conventional world oil production.

B. The Optimism

As recently as 2001, a number of credible groups were optimistic about the ready availability of natural gas in North America. For example:

• In 1999 the National Petroleum Council stated “U.S. production is projected to increase from 19 trillion cubic feet (Tcf) in 1998 to 25 Tcf in 2010 and could approach 27 Tcf in 2015…. Imports from Canada are projected to increase from 3 Tcf in 1998 to almost 4 Tcf in 2010.” [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]

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]

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.

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 observations:

• Like oil reserves estimation, natural gas reserves estimation is subject to enormous uncertainty. North American natural gas reserves estimates now appear to have been excessively optimistic and North American natural gas production is now almost certainly in decline.
• High prices do not a priori lead to greater production. Geology is ultimately the limiting factor, and geological realities are clearest after the fact.
• Even when urgent, nation-scale energy problems arise, business-as-usual mitigation activities can be dramatically delayed or stopped by state and local opposition and other factors.

If experts were so wrong on their assessment of North American natural gas, are we really comfortable risking that the optimists are correct on world conventional oil production, which involves similar geological and technological issues?

If higher prices did not bring forth vast new supplies of North American natural gas, are we really comfortable that higher oil prices will bring forth huge new oil reserves and production, when similar geology and technologies are involved?

VI. MITIGATION OPTIONS AND ISSUES

A. Conservation

Practical mitigation of the problems associated with world oil peaking must include fuel efficiency technologies that could impact on a large scale. Technologies that may offer significant fuel efficiency improvements fall into two categories: retrofits, which could improve the efficiency of existing equipment, and displacement technologies, which could replace existing, less efficient 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 scale.

From our prior discussion of current liquid fuel usage (Chapter III), it is clear that automobiles and light trucks (light duty vehicles or LDVs) represent the largest targets for consumption reduction. This should not be surprising: Auto and LDV fuel use is large, and fuel efficiency has not been a consumer priority for decades, largely due to the historically low cost of gasoline. An established but relatively little-used engine technology for LDVs in the U.S. is the diesel engine, which is up to 30 percent more efficient than comparable gasoline engines. Future U.S. use of diesels in LDVs has been problematic due to increasingly more stringent U.S. air emission requirements. European regulations are not as restrictive, so Europe has a high population of diesel LDVs — between 55 and 70 percent in some countries. [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 on-the-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 fuel.

Government-mandated vehicle fuel efficiency requirements are virtually certain to be an element in the mitigation of world oil peaking. One result would almost certainly be the more rapid deployment of diesel and / or hybrid engines. Market penetration of these technologies cannot happen rapidly, because of the time and effort required for manufacturers to retool their factories for large-scale production and because of the slow turnover of existing stock. In addition, a shift from gasoline to diesel fuel would require a major refitting of refineries, which would take time.

Nation-scale retrofit of existing LDVs to provide improved fuel economy has not received much attention. One retrofit technology that might prove attractive for the existing LDV fleet is “displacement on demand” in which a number of cylinders in an engine are disabled when energy demand is low. The technology is now available on new cars, and fuel economy savings of roughly 20 percent have been claimed. [70] The feasibility and cost of such retrofits are not known, so we consider this option to be speculative.

It is difficult to project what the fuel economy benefits of hybrid or diesel LDVs might be on a national scale, because consumer preferences will likely change once the public understands the potential impacts of the peaking of world oil production. For example, the current emphasis on large vehicles and SUVs might well give way to preferences for smaller, much more fuel-efficient vehicles.

The fuel efficiency benefits that hybrids might provide for heavy-duty trucks and buses are likely smaller than for LDVs for a number of reasons, including the fact that there has long been a commercial demand for higher efficiency technologies in order to minimize fuel costs for these fleets.

Hybrids can also impact the medium duty truck fleet, which is now heavily populated with diesel engines. For example, road testing of diesel hybrids in FedEx trucks recently began, with fuel economy benefits of 33 percent claimed. [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 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.

Improved Oil Recovery (IOR) is used to varying degrees on all oil reservoirs. IOR encompasses a variety of methods to increase oil production and to expand the volume of recoverable oil from reservoirs. Options include in-fill drilling, hydraulic fracturing, horizontal drilling, advanced reservoir characterization, enhanced oil recovery (EOR), and a myriad of other methods that can increase the flow and recovery of liquid hydrocarbons. IOR can also include many seemingly mundane efficiencies introduced in daily operations. [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 possible.

A particularly notable opportunity to increase production from existing oil reservoirs is the use of enhanced oil recovery technology (EOR), also known as tertiary recovery. EOR is usually initiated after primary and secondary recovery have provided most of what they can provide. Primary production is the process by which oil naturally flows to the surface because oil is under pressure underground. Secondary recovery involves the injection of water into a reservoir to force additional oil to the surface.

EOR has been practiced since the 1950s in various conventional oil reservoirs, particularly in the United States. The process that likely has the largest worldwide potential is miscible flooding wherein carbon dioxide (CO₂), nitrogen or light hydrocarbons are injected into oil reservoirs where they act as solvents to move residual oil. Of the three options, CO₂ flooding has proven to be the most frequently useful. Indeed, naturally occurring, geologically sourced CO₂ has been produced in Colorado and shipped via pipeline to west Texas and New Mexico for decades for EOR. CO₂ flooding can increase oil recovery by 7-15 percent of original oil in place (OOIP). [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.

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.

C. Heavy Oil and Oil Sands

This category of unconventional oil includes a variety of viscous oils that are called heavy oil, bitumen, oil sands, and tar sands. These oils have potential to play a much larger role in satisfying the world’s needs for liquid fuels in the future.

The largest deposits of these oils exist in Canada and Venezuela, with smaller resources in Russia, Europe and the U.S. While the size of the Canadian and Venezuela resources are enormous, 3-4 trillion barrels in 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]

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]

In addition to needing a substitute for natural gas for processing oil sands, there are a number of other major challenges facing the expansion of Canadian oil sands production, including water [81] and diluent availability, financial capital, and environmental issues, such as SO_X and NO_X emissions, waste water cleanup, and brine, coke, and sulfur disposition. In addition, because Canada is a signatory to the Kyoto Protocol and because oil sands production results in significant CO₂ emissions per barrel, there may be related constraints yet to be fully evaluated.

The current Canadian vision is to produce a total of about 5 MM bpd of products from oil sands by 2030. This is to include about 3 MM bpd of synthetic crude oil from which refined fuels can be produced, with the remainder being poorer quality bitumen that could be used for energy, power, and/or hydrogen and petrochemicals production. 5 MM bpd would represent a five-fold increase from current levels of production. [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.

In closing, it is also worth noting that the bitumen yield from oil sands surface mining operations is about 0.6 barrels per ton of mined material, excluding overburden removal. This is similar to the yield from a good quality oil shale, but is less than Fisher-Tropsch liquid yields from coal, which is about 2.6 barrels per ton of coal. [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-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 terminated. [92]

The oil shale processing technologies that were pursued in the past required large volumes of water, which is now increasingly scarce in the western states. Also, air emissions regulations have become much stricter in the ensuing years, presenting additional challenges for shale mining and processing. Finally, it should be noted that the oil produced from shale retorting requires refining before it can be used as transportation fuels.

In recent years, Shell has been developing a new shale oil recovery process that uses 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.

In the 1990s electric automobiles were introduced to the market, spurred by a California clean vehicle requirement. The effort was a failure because existing batteries did not provide the vehicle range and performance that customers demanded. In the future, electricity storage may improve enough to win consumer acceptance of electric automobiles. In addition, extremely high gasoline prices may cause some consumers to find electric automobiles more acceptable, especially for around-town use. Such a shift in public preferences is unpredictable, so electric vehicles cannot now be projected as a significant offset to future gasoline use.

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

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

H. Hydrogen

Hydrogen has potential as a long-term alternative to petroleum-based liquid fuels in some transportation applications. Like electricity, hydrogen is an energy carrier; hydrogen production requires an energy source for its production. Energy sources for hydrogen production include natural gas, coal, nuclear power, and renewables. Hydrogen can be used in internal combustion engines, similar to those in current use, or via chemical reactions in fuel cells.

The Department of Energy is currently conducting a high profile program aimed at developing a “hydrogen economy.” [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 highlights.

A lynchpin of the current DOE hydrogen program is fuel cells. In order for fuel cells to compete with existing petroleum-based internal combustion engines, particularly for light duty vehicles, the NRC concluded that fuel cells must improve by 1) a factor of 10-20 in cost, 2) a factor of five in lifetime, and 3) roughly a factor of two in efficiency. The NRC did not believe that such improvements could be achieved by technology development alone; instead, new concepts (breakthroughs) will be required. In other words, today’s technologies do not appear practically viable. [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.

I. Factors That Can Cause Delay

It is extremely difficult, expensive, and time consuming to construct any type of major energy-related facility in the U.S. today. Even assuming the expenditure of substantial time and money, it is not certain that many proposed facilities will ever be constructed. The construction of transmission lines, interim and permanent nuclear waste disposal facilities, electric generation plants, waste incinerators, oil refineries, LNG terminals, waste recycling facilities, petrochemical plants, etc. is increasingly problematic.

What used to be termed the “not-in-my-back-yard” (NIMBY) principle has evolved into the “build-absolutely-nothing-anywhere-near-anything” (BANANA) principle, which is increasingly being applied to facilities of any type, including low-income housing, cellular phone towers, prisons, sports stadiums, water treatment facilities, airports, hazardous waste facilities, and even new fire houses. [99] Construction of even a single, relatively innocuous, urgently needed facility can easily take more than a decade. For example, in 1999, King County, Washington, initiated the siting process for the Brightwater wastewater treatment plant, which it hopes to have 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 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.

VII. A WORLD PROBLEM

Oil is essential to all countries. In 2002 daily consumption ranged from almost 20 million barrels in the U.S. to 20 barrels in the tiny South Pacific island of Niue, population 2,400. [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.

VIII. THREE MITIGATION SCENARIOS

A. Introduction

Issues related to the peaking of world oil production are extremely complex, involve literally trillions of dollars and are very time-dependent. To explore these matters, we selected three mitigation scenarios for analysis:

• Scenario I assumes that action is not initiated until peaking occurs.
• Scenario II assumes that action is initiated 10 years before peaking.
• Scenario III assumes action is initiated 20 years before peaking.

Our approach is simplified in order to provide transparency and promote understanding. Our estimates are approximate, but the mitigation envelope that results is believed to be indicative of the realities of such an enormous undertaking.

B. Mitigation Options

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

C. Mitigation Phase-In

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

D. The Use of Wedges

The model chosen to illustrate the possible effects of likely mitigation actions involves the use of “delayed wedges” to approximate the scale and pace of each action. The use of wedges was effectively utilized in a recent paper by Pacala and Socolow. [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.

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]

Our aim is to approximate reality in a simple manner. Greater detail is beyond the scope of this study and would require in-depth analysis.

E. Criteria for Wedge Selection

Our criteria for selecting candidates for our energy saving and substitute oil
production wedges were as follows:

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

F. Wedges Selected & Rejected

The combination of technologies, processes, and feedstocks that meet these criteria are as follows:

1. Fuel efficient transportation,
2. Heavy oil/Oil sands,
3. Coal liquefaction,
4. Enhanced oil recovery,
5. Gas-to-liquids.

In the end-use category, a dramatic increase in the efficiency of petroleum-based fuel equipment is one attractive option. As previously described, the imposition of CAFE requirements for 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]

The fuels production options that we chose are heavy oil/tar sands, coal liquefaction, improved oil recovery, and gas-to-liquids. Our rationale was as follows:

1. Enhanced Oil Recovery is applicable worldwide.
2. Heavy oil / 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 markets.

We excluded a number of options for various reasons. While the U.S. has a huge resource of shale oil that could be processed into substitute liquid fuels, the technology to accomplish that task is not now ready for deployment. Because various shale oil processing prototypes were developed in years past and because shale oil processing is likely to be economically attractive, a concerted effort to develop shale oil technology could well lead to shale oil becoming a contributor in Scenarios II or III. However, that would require the initiation of a major R & D program in the near future.

Biomass options capable of producing liquid fuels were also excluded. Ethanol from biomass is currently utilized in the transportation market, not because it is commercially competitive, but because it is mandated and highly subsidized. Biodiesel fuel is a subject of considerable current interest but it too is not yet commercially viable. Again, a major R & D effort might change the biomass outlook, if initiated in the near future. [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 the many-decade future after oil peaking, it is conceivable that a massive shift from liquid fuels to electricity might occur in some applications. However, consideration of such changes would be speculative at this time.

It is possible that technology innovations resulting from aggressive future research may well change the outlook for various technologies in the future. Our focus on the currently viable is in no way intended to prejudice other future options. We have chosen not to add a wedge for undefined technologies that might result from accelerated research, because such a wedge would be purely speculative. No matter what the new technology(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

It is not possible to predict with certainty when world conventional oil peaking will occur or how rapidly production will decline after the peak. To develop our scenarios, we utilize the U.S. Lower 48 production pattern as a surrogate for the world. This assumption is justified on the basis that Lower 48 oil production represents what really happened in a large, complex oil province over the course of decades of modern oil production development.

Our 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 only.

Next is the important issue of the slopes of the production profile showing the rate of growth of production/demand before peaking and the subsequent decline in production. The World Energy Council stated: “Oil demand is projected to increase at about 1.9 percent per year rising from about 75.7 million b/d in 2000 (actual) to 113-115 million b/d in 2020 — an increase of about 37.5-39.5 million b/d.” [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 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

In 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.

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.

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 improvements.

Our results are congruent with the fundamentals of the problem:

• Waiting until world oil production peaks before taking crash program action leaves the world with a significant liquid fuel deficit for more than two decades.
• Initiating a mitigation crash program 10 years before world oil peaking helps considerably but still leaves a liquid fuels shortfall roughly a decade after the time that oil would have peaked.
• Initiating a mitigation crash program 20 years before peaking appears to offer the possibility of avoiding a world liquid fuels shortfall for the forecast period.

The obvious conclusion from this analysis is that with adequate, timely mitigation, the costs of peaking can be minimized. If mitigation were to be too little, too late, world supply/demand balance will be achieved through massive demand destruction (shortages), which would translate to significant economic hardship, as discussed earlier.

K. Risk Management

It is possible that peaking may not occur for several decades, but it is also possible that peaking may occur in the near future. We are thus faced with a daunting risk management problem:

• On the one hand, mitigation initiated soon would be premature if peaking is still several decades away.
• On the other hand, if peaking is imminent, failure to initiate mitigation quickly will have significant economic and social costs to the U.S. and the world.

The two risks are asymmetric:

• Mitigation actions initiated prematurely will be costly and could result in a poor use of resources.
• Late initiation of mitigation may result in severe consequences.

The world has never confronted a problem like this, and the failure to act on a timely basis could have debilitating impacts on the world economy. Risk minimization requires the implementation of mitigation measures well prior to peaking. Since it is uncertain when peaking will occur, the challenge is indeed significant.

IX. MARKET SIGNALS AS PEAKING IS APPROACHED

As world oil peaking is approached and demand for conventional oil begins to exceed supply, oil prices will rise steeply. As discussed in Chapter IV, related price increases are almost certain to have negative impacts on the U.S. and world economies. Another likely signal is substantially increased oil price volatility.

Oil prices have traditionally been volatile. Causes include political events, weather, labor strikes, infrastructure problems, and fears of terrorism. [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 rates. [116]

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]

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.

In conclusion, oil peaking will not only lead to higher oil prices but also to increased oil price volatility. In the process, oil could become the price setter in the broader energy market, in which case other energy prices could well become increasingly volatile and unpredictable. [119]

X. WILDCARDS

There are a number of factors that could conceivably impact the peaking of world oil production. Here is a list of poss