13 9

R O U N D TA B L E

This report includes an examination of the factorsthat drive oil prices in the short and long term anda discussion of the outlook for oil supply.

139

www.internationaltransportforum.org

www.oecd.org/publishing(74 2008 03 1 P1) ISBN 978-92-82-10121-6-:HSTCSC=VUVWV[:2008

R E S E AR C HThis Round Table assesses the policy instruments
available to address oil security and climate change
and examines their interaction with measures tomanage congestion and mitigate local air pollution.
A number of incompatibilities and trade-offs
are identified underlining the importance ofintegrated policy making.

T r a n s p o r t

OPEC market power is increasing as production of
conventional oil outside OPEC has reached a plateau.
Oil from tar sands in Canada and elsewhere is available
in very large quantities, and is competitive at sustained
prices above $40 a barrel. But processing such oil
doubles CO2 emissions on a well-to-wheels basis
compared to using conventional oil to fuel transport.

Oil Dependence: Is Transport Running Out
of Affordable Fuel?

Oil consumption is increasingly concentrated intransport and relatively limited fluctuations in transportdemand can have increasingly significant effects on oil
prices. Oil prices rose to all time highs at the beginningof 2008, exceeding $100 a barrel for the first timesince the 1979 oil crisis. The underlying driver was
demand for oil from rapidly developing economies
and especially China, where transport accounts forthe largest part of oil consumption.

C E N T r e

Oil Dependence:
Is Transport Running Out
of Affordable Fuel?

Oil Dependence:
Is Transport
Running Out
of Affordable Fuel?

ROUND
TABLE

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T r a n s p o r

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ROUND
TABLE

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Oil Depen ence:s Transp running Ou
f ff r able uel?

ORGANISATION FOR ECONOMIC CO-OPERATION
AND DEVELOPMENTThe OECD is a unique forum where the governments of 30 democracies work together toaddress the economic, social and environmental challenges of globalisation. The OECD is also at
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Also available in French under the title:PÉTROLE ET TRANSPORT : LA FIN DES CARBURANTS À PRIX ABORDABLE ?

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INTERNATIONAL TRANSPORT FORUM

The International Transport Forum is an inter-governmental body within the OECD family. The Forumis a global platform for transport policy makers and stakeholders. Its objective is to serve political leaders
and a larger public in developing a better understanding of the role of transport in economic growth and therole of transport policy in addressing the social and environmental dimensions of sustainable development.
The Forum organises a Conference for Ministers and leading figures from civil society each May in Leipzig,
Germany.
The International Transport Forum was created under a Declaration issued by the Council of
Ministers of the ECMT (European Conference of Ministers of Transport) at its Ministerial Session in May
2006 under the legal authority of the Protocol of the ECMT, signed in Brussels on 17 October 1953, andlegal instruments of the OECD. The Forum's Secretariat is located in Paris.
The members of the Forum are: Albania, Armenia, Australia, Austria, Azerbaijan, Belarus, Belgium,
Bosnia-Herzegovina, Bulgaria, Canada, Croatia, the Czech Republic, Denmark, Estonia, Finland, France,
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The OECD and the International Transport Forum established a Joint Transport Research Centre in
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Further information about the International Transport Forum is available on Internet at the following address:www.internationaltransportforum.org

TABLE OF CONTENTS -5

TABLE OF CONTENTS

SUMMARY OF DISCUSSIONS.......................................................................................................... 7

INTRODUCTORY REPORTS:
Peak Oil and the Evolving Strategies of Oil Importing and Exporting Countries,
by Kjell ALEKLETT (Sweden) .................................................................................................. 37
1.
2.
3.
4.
5.
6.
7.

Introduction ............................................................................................................................ 43
Future Demand for Oil ........................................................................................................... 48
How Much Oil Have We Found and When Did We Find It? ................................................ 53
Historical Consumption and Limits for Future Consumption ................................................ 60
Import and Export Scenarios.................................................................................................. 72
Production of Transport Liquids with CTL and GTL ............................................................ 78
Possible Strategies for Oil Importing and Oil Exporting Countries....................................... 82

8.

Awareness of Peak Oil ............................................................................................... 86

Appendix: Reserve-Driven Forecasts for Oil, Gas and Coal and Limits of Carbon Dioxide
Emissions: Peak Oil, Peak Gas, Peak Coal and Peak CO2 ....................................... 95

Future Prices and Availability of Transport Fuels,
by David L. GREENE (USA) ....................................................................................... 115
1.
2.
3.
4.
5.

Introduction .............................................................................................................. 119
Growing Transport Fuel Demand ............................................................................. 122
Resources, OPEC and the Oil Transition ................................................................. 124
Policy and Technological Change ............................................................................ 134
The Outlook for Transportation Energy Prices ........................................................ 137

Medium-Term Oil Market Uncertainties, by Lawrence EAGLES (IEA) ............... 147
1.
2.
3.
4.

Overview .................................................................................................................. 151
Supply-Side Uncertainties ........................................................................................ 158
Investment ................................................................................................................ 161
Conclusion ................................................................................................................ 163

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6 - TABLE OF CONTENTS
Long-run Trends in Transport Demand, Fuel Price Elasticities and Implicationsof the Oil Outlook for Transport Policy,
by Kenneth A. SMALL (USA) and Kurt VAN DENDER (ITF) ........................................... 165
1. Introduction .................................................................................................................... 171
2. The Determinants of Road Passenger Transport Demand and Derived
Energy Demand in the Long Run.............................................................................. 172
3. Energy Policy in Transport ............................................................................................ 183
4. Conclusion ..................................................................................................................... 191

LIST OF PARTICIPANTS ....................................................................................................... 201

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SUMMARY OF DISCUSSIONS -SUMMARY OF DISCUSSIONSOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 – © OECD/ITF, 2008

7

SUMMARY OF DISCUSSIONS -9

SUMMARY CONTENTSEXECUTIVE SUMMARY ................................................................................................................... 11
1.

INTRODUCTION ......................................................................................................................... 15

2.

OIL PRICES DRIVERS 1960 TO 2007........................................................................................ 15

3.

OIL PRICE VOLATILITY AND CYCLICAL EFFECTS ........................................................... 17

4.

THE SHORT RUN OIL PRICE OUTLOOK................................................................................ 18

5.

LONG-TERM OIL SUPPLY OUTLOOK .................................................................................... 19

6.

NON-CONVENTIONAL OIL ...................................................................................................... 20

7.

DOES A PRICE OF $100 A BARREL OF OIL MATTER? ........................................................ 21

8.

TRANSPORT SECTOR RESPONSES TO CHANGES IN OIL PRICES ................................... 229.

MOTIVATING TRANSPORT POLICIES – MARKET FAILURES .......................................... 23

10. POLICY INSTRUMENTS ............................................................................................................ 24
Fuel excise duty and carbon tax .................................................................................................... 24
Vehicle efficiency regulations ....................................................................................................... 27
11. DESIGNING TRANSPORT POLICIES: THE NEED FOR INTEGRATING TRANSPORT,ENVIRONMENT AND ENERGY DIMENSIONS ..................................................................... 29
NOTES .................................................................................................................................................. 31
BIBLIOGRAPHY ................................................................................................................................. 32

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SUMMARY OF DISCUSSIONS -11

EXECUTIVE SUMMARY

The transport sector’s demand for oil is less price sensitive than any other part of the economy.
This is partly because demand for transport services is relatively insensitive to price and partly
because substitutes for oil in road transport are currently far from cost-effective. Evidence from the
USA suggests that as incomes rise, transport sector oil demand becomes even less price sensitive. Thisimplies that oil consumption is set to become increasingly concentrated in the transport sector. It also
implies that relatively limited fluctuations in demand can have increasingly significant effects on oil
prices.
Figure 1. Spot crude oil price 1970-2007: real and nominal prices$/bbl

WTI Nominal

WTI Real, base = Dec 2007

120

100

80

60

40

20

0
1970

Notes:

1975

1980

1985

1990

1995

2000

2005

Price sources: Dow Jones for pre-Jan 1985 data, Platts monthly Cushing spot west Texas
intermediate (WTI) crude from Jan 1985; Deflated taking December 2007 baseline and using
monthly OECD consumer price index data.

Source: IEA.

Oil prices approached their historical 1980 peak in real terms in November 2007, when the
Round Table convened (see Figure 1). Because of growth in incomes since 1980 and the reduced oil
dependence of OECD economies, the economic impact of high prices has been weaker than during
earlier oil price peaks. Moreover, the current high prices are a result of strong economic growth rather
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12 – SUMMARY OF DISCUSSIONS
than a supply shock as was the case in the oil crises of the 1970s. Nevertheless, the transport sector isthe most exposed part of the economy to oil prices.
OPEC market power is expected to increase. OPEC, and particularly the Middle East, will see its
share world oil supply increase because production of conventional oil from other parts of the world
has either peaked and entered a phase of permanent decline or reached a plateau for the foreseeable
future. OPEC will therefore be in a strong position to defend high prices against a background ofrising demand, particularly from the emerging economies.
That is not to say prices will inevitably rise further or even stay at current levels. They could also
fall substantially if economic growth weakens, particularly in the increasingly interdependent US andChinese economies. Price instability is likely to persist. This creates uncertainties that delay major
investments in new oil production and refining capacity, as well as in fuel efficient car technology.
In the longer term, non-conventional oil resources could supply a large part of oil demand at prices
from around $40 a barrel. The conventional view is that reserves of tar sands, oil shale and coal are
sufficient to provide for decades of further growth in oil consumption, but this was challenged bysome Round Table participants who believe coal supply has already peaked. As non-conventional oil
sources become more critical to world oil supply, a better understanding of their availability and theeconomics of production is increasingly important.
Policy responses to growing OPEC market power can seek to either promote non-conventional
oil production in non-OPEC countries or reduce oil consumption. Policies to promote alternative fuels
are also relevant but of limited short term potential as discussed in the conclusions of the JTRC Round
Table on Biofuels: Linking Support to Performance (OECD/ITF 2007). Non-conventional sources ofoil are associated with more than twice the emissions of greenhouse gasses from conventional oil.
Their development may therefore be constrained by climate policy.
Intervention to internalize the costs of CO2 emissions from transport serves to both mitigate
climate change and reduce oil consumption at the same time. Carbon taxes are the preferred
instrument of many economists to achieve this because they provide incentives for attainment of theenvironmental target at least-cost. However, vehicle fuel efficiency or CO2 emissions standards havesome advantages, not least in terms of political acceptability. They are also able to correct thedifference between social and private discount rates at the point of vehicle purchase. Differences
between social and private discount rates, and imperfections in consumers’ decisions on what fueleconomy to buy, may justify standards even if taxes reflect external costs.
Standards are vulnerable to being undermined by the rebound effect – i.e. the cost savings
resulting from increased fuel efficiency may be taken up by additional driving or upgrading of thepower or weight of the vehicles purchased. There is considerable agreement that the rebound effect interms of increased driving is small (around 20%, maybe smaller1), so that standards do translate into
substantial reductions in fuel consumption. To the extent that the rebound effect is a problem, it
indicates a failure to price CO2 emissions and other transport externalities correctly. This suggests that
if a standard is the primary tool adopted for reducing transport sector CO2 emissions a secondary tax
element is required – ideally in the form of a carbon tax or alternatively through fuel taxes ordifferentiation of taxes on vehicle purchase or ownership. It also increases the urgency of introducing
tools to manage congestion.
Transport, environment and oil security policies interact in a number of ways and there are tradeoffs beyond the environmental impacts of developing non-conventional oil. Dieselisation of the car
fleet, initially triggered by relatively low taxes on diesel fuels, has been the cornerstone of progress in
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SUMMARY OF DISCUSSIONS -13

Europe to reduce CO2 emissions from the transport sector. As a consequence, the market share ofdiesel has grown strongly and has reached almost 70% of road transport fuels in the EU. But there arelimits to the degree to which the refining process can switch production from one type of fuel toanother without consuming large additional amounts of energy to convert oil products. The excess
diesel demand in Europe is currently met through trade, with diesel imported from Russia and the
USA and gasoline exported from Europe to America. If any other major car market were to follow thedieselization path, diesel prices would rise sharply and CO2 emissions would increase.
Two important issues arise when the energy security and greenhouse gas emissions fromtransport are viewed from a broader perspective. First, there is the question of how to distributegreenhouse gas abatement efforts among different sectors. Cost-effective CO2 abatement strategies
should aim to distribute efforts over sectors efficiently. The challenge is to minimize simultaneously
CO2 abatement costs, potential losses in the competitiveness of industry and the costs of energy importdependence. In this sense, the large share of transport in total CO2 emissions in itself provides little
guidance on how large this sector’s contribution should be, although it needs to be recognised that thepolitical process very likely will request a substantial contribution from transport to cutting overall
emissions.
Second, intervention to reduce greenhouse gas emissions from the transport sector needs to be
integrated with policies to reduce the other external costs of transport – local air pollutants, accidents
and especially congestion. Congestion costs greatly outweigh the cost of CO2 emissions from transportaccording to most studies. The large impact on CO2 emissions (-20%) of congestion charges in
London and Stockholm suggests that congestion management can facilitate the attainment of CO2
reduction targets in congested areas.

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SUMMARY OF DISCUSSIONS -15

1. INTRODUCTION

Crude oil prices were nearly 100 dollars a barrel when the Round Table convened in November
2007. In real dollar values, this matched the historic peak in oil prices of 1980 (Figure 1). The gradualrise in oil prices to these levels over the last five years was driven fundamentally by growing demand,
especially from China, in combination with limited elasticities of supply. Whilst the outlook for supply
and demand suggests prices are likely to remain high in the next five years, any slowdown in world
trade and economic growth would result in a fall in oil prices, and probably a large fall. Whether
prices rise or fall, they are expected to continue to be characterized by sharp spikes and troughs.
The Round Table examined the factors that drive oil prices and those likely to be most important
over the next 25 years. It then reviewed recent evidence on the response of road transport activity tochanges in fuel prices in order to explore linkages between transport and energy policies. The Round
Table also examined the outlook for oil supply, together with the implications for climate policy ifvery heavy crude oils, tar sands, oil shales or coal-to-liquid fuels are developed on a large scale.
Discussions then turned to potential policy responses, on the supply side and on the demand side,
revealing some critical trade-offs between climate change and oil security policies. If theseinteractions are ignored, energy policies in the transport sector could result in large unnecessary costs.

2. OIL PRICES DRIVERS 1960 TO 2007

The impact on oil prices of action by the Organization of Petroleum Exporting Countries (OPEC)
to restrict oil supplies in 1973 and 1979 is obvious in Figure 1. The motivation for restricting supply
was in both cases political (the Yom Kippur War and the Iranian revolution) rather than aimed at
maximizing profits2 but coincided with peaking of US oil production, which endowed OPEC withmarket power to control prices. OPEC subsequently used this power to defend high oil prices by
setting production quotas for its members. Although oil producers in the USA were unable to expand
supply, the high prices did drive exploration and rapid development of oil fields in other non-OPEC
countries. This gradually eroded OPEC market power until the point in 1985/6 when prices collapsed.
This price collapse stranded high-cost investments made by the major oil companies. The effects
are still felt today, with a strong aversion to (over-) investing in oil production, oil refining and fuelefficiency on the part of private oil companies and car manufacturers. The consequence is that supply
is not very elastic, even with strongly rising demand. And uncertainty over future prices, as well as
rising resource costs for extraction and refining, further discourages major investments.

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16 – SUMMARY OF DISCUSSIONS
Even during periods of market dominance, OPEC decisions on production targets havesometimes resulted in sharp falls in prices, underlining the uncertainties in the market. The net effect is
to increase upward pressure on oil prices.
David Greene traces these developments in price and market power in his report for the Round
Table (Greene, 2007), summarized in Figure 2. The graph plots upper and lower bounds for oil prices,
assuming OPEC seeks to maximize profit, as a function of short and long run oil price elasticities andas a function of conditions of supply outside OPEC. The maximum price band is calculated on thebasis of short-run price elasticities for oil demand, i.e. the potential for rapid oil substitution anddemand reduction in response to price increases, and short run elasticities for oil supply from the restof the world. The lower band is based on the larger, long-run elasticities of demand and supply. These
account for changes that take time to affect the market, such as the introduction of more fuel efficient
vehicles or oil substitution in other industries.
Figure 2. World oil prices since 1965 in the context of
OPEC’s long- and short-run profit-maximizing price functions

Cartel Market Share and World Oil Prices: 1965-2006
$100
$90

1979

2006 $/Barrel

$80
$70

2006

$60
$50

1974

1985
1990

$40
$30
$20

2000
1986

1998
1965

$10
$0
25%

30%

35%

40%

45%

50%

55%

OPEC 11 Market Share
Source: Greene 2007.
It should be underlined that the upper limit band is rather wide because short-run supply anddemand elasticities are not easily calculated. It should also be noted that the band indicates a range forprice trends and not an absolute limit. In particular, given that the underlying model is deterministic,
prices can substantially overshoot these bounds for short periods.
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SUMMARY OF DISCUSSIONS -17

Nevertheless, Figure 2 suggests a strong positive relation between OPEC market power andprices. Plotting historical prices on this framework reveals that until 1973 oil prices were below thelower bound. In 1979, OPEC raised prices to the level of the upper band and had sufficient market
power to defend prices in this band through 1985. The cartel was able to increase profits by cutting
output until a point where their market share fell below 30% of world oil supply. At this point longer
term demand and supply responses started to be felt, discipline broke down in the cartel, production
quotas were exceeded and the oil price collapsed, falling close to the lower bound of the model. OPEC
nevertheless continued to control the bulk of low-cost oil production capacity and gradually recovered
market share.
What does the analysis tell us about more recent history and about the near future? Production of
conventional oil in non-OPEC countries is not expected to expand rapidly in response to current highoil prices. Some analysts foresee continuous decline and most expect a prolonged plateau in overall
production levels. Extraction rates from existing oil fields cannot be accelerated beyond the limits
imposed by the physical characteristics of each reservoir and the development of new sources is
uncertain and slow. The bottom line is that in the near future the Middle East is expected to produce arising share of world oil supply, which will tend to increase OPEC’s market power.
In terms of Figure 2, current oil prices and OPEC market share are close to conditions thatprevailed in the second oil shock. With a tendency for both oil demand and the cartel’s market share toincrease, OPEC is likely to be able to defend prices and maintain large economic rents for several
years, until longer term responses begin to be felt.

3. OIL PRICE VOLATILITY AND CYCLICAL EFFECTS

In addition to the overall supply and demand balance and OPEC production rates, a large numberof other factors can have a significant influence crude oil and oil product prices in the short term. On
the supply side these include wars, political unrest, strikes, storms and hurricanes, accidents andunexpected maintenance. Refining is vulnerable to a similar set of problems. Crude oil and oil productstocks provide a buffer between supply and demand but stock changes can also have a strong influenceon prices. On the demand side the most significant factors are colder or milder than average winterheating periods and economic downturns. Both crude and products are traded on international
exchanges that have developed forward contracts to manage the price risks. Interaction between
contract, spot and forward markets, between crude and product markets and between different types oftrader increases the complexity of price behaviour.
At the time the Round Table took place crude oil prices on the spot market were higher than on
futures markets. This had been the situation for some weeks, with forward prices falling the further
into the future the date for settlement, despite a general expectation that oil supplies would remaintight. With this configuration of prices3 there is pressure for traders to sell on the spot market and buyon the futures market until prices even out. However, the gains to be made this way have to beassessed against supply security, oil quality and timing of delivery risks. Refiners, which are an
important part of the market, can only sell part of their inventory as they need to hold stocks forrefining. The size of the gap between spot and futures prices is sometimes taken as a measure of theOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 – © OECD/ITF, 2008

18 – SUMMARY OF DISCUSSIONS
tightness of supply, but the situation is unstable and eventually there is a readjustment of prices, oftena sharp fall in spot prices.
Although oil product prices are dependent on the price of crude oil they are also subject to tradingpressures of their own. At the time of the Round Table oil refiners and distributors held sufficient
stocks of products that competition between them to supply the end user markets coupled with a fearthat further price increases would suppress demand prevented them fully passing on increases in thecost of crude oil to consumers. This ended a five-year run of unusually high refining margins, and is
now expected to squeeze investment in new refining capacity.
Cuts in refinery investment will affect the supply and price of products in the future. This lagged
effect is characteristic of both refining and crude oil production, driving cycles of over and under
supply. Cycles initiated by the oil crises of the 1970s and the subsequent oil price collapse of 1985-86
continue to have an influence on markets today.

4. THE SHORT RUN OIL PRICE OUTLOOKThere are a very large number of factors that drive oil prices in the short term, but their impact
depends ultimately on the fundamental balance between supply and demand. Sustained expansion of
global economic activity is the underlying reason oil prices have risen to current levels, withconsequent demand for oil expanding ahead of supply. Continued strong demand, particularly from
China, is expected to maintain these oil market conditions for some time. China’s economy isvulnerable, however, to any slowdown in demand for its exports. The difficulties in financial markets
that began with the sub-prime mortgage crisis in the USA in 2007 illustrates the downside risks;
China’s industry Minister has warned of the potential for a sharp downturn in Chinese output as aresult. (Financial Times, 16 October 2007).
Above ground constraints currently play a greater role in determining oil supply and prices thanthe long term dynamics of oil reserves, exploration and production. The most important is costescalation in the oil services industry (drilling, oilfield development and pipeline construction) due toshortages of skilled labour and increases in the costs of raw materials.
Social and political tensions have depressed production in a number of regions, notably Nigeria
and Venezuela, and war in Iraq has taken a large part of that country’s potential output out ofcommission. In the medium term, output from these regions is expected to be restored, albeit underarrangements that allow for profit maximizing under OPEC coordination. More generally, it was notedthat oil production concession agreements that provide lower rents (after adjusting for production
costs) than in OPEC and other countries are inherently unstable, leading to renegotiation andeventually adjustment of the agreements.
Changes in the taxation of oil field development and production also have an impact. This
concerns not only renegotiation of concession conditions in countries like Venezuela but also OECD
countries where, for example, tax changes in the UK sector of the North Sea have depressed
exploration and development activity.

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SUMMARY OF DISCUSSIONS -19

The refining investment cycle mentioned already above could also affect prices for transport fuels
over the coming five years. The oil majors lost large amounts of money in refining in the period 1996
to 2003 and as a result cut investment. The consequence was a shortage of capacity in the period 2004
to 2007 that helped drive up prices. New capacity is now coming on stream, particularly in the Middle
East and India. More generally there has been investment in converting heavy fuel oil into diesel andother higher value products. This could result in over-supply of the market and falling prices in themedium term, although opinions are divided as to how likely this is.

5. LONG TERM OIL SUPPLY OUTLOOK

Kjell Aleklett’s paper for the Round Table examines the production history of oil fields aroundthe world stressing the inevitable eventual decline in output from all fields. Aleklett’s paper also
makes the important point that there are physical limits to the rate at which petroleum can be extracted
from oil fields, determined by the characteristics of the reservoir and the oil. This limits the rate at
which extraction from fields already in production can be increased in response to increasing demandor in response to supply disruptions. Based on work at Uppsala and Reading Universities, whichmodels oil field development field by field around the world, the paper suggests non-OPEC
production is already in irreversible decline and that the peak in production of conventional oil
globally will arrive in only a few years, with an irreversible decline setting in thereafter.
This contrasts to analyses by the US Energy Information Administration (EIA) and theInternational Energy Agency (IEA), which foresee a prolonged plateau in non-OPEC productionlevels and do not rule out increases in production from new fields nor as a result of technologicalinnovation. With strong growth in oil demand, either a decline or a plateau in non-OPEC production
indicates increasing market power for OPEC in the future.
Views on potential production in the Middle East diverge sharply, largely because data on
reserves in the region are poor. The Association for Peak Oil foresees an imminent peak and Aleklett’s
paper incorporates new data from Saudi Arabia reinforcing this view. The view is supported by anumber of other analyses, reviewed in Boyle and Bentley 2007 contrasting with the conventional viewthat the peak is far enough away, or that sufficient non-conventional oil reserves can be developed atprices above $40/bbl, to ensure oil-based energy for transport for the foreseeable future.
The models on which the peak oil analyses are based are no more uncertain, and rather lesscomplex, than models of climate change and merit similarly serious consideration. One implication forclimate policy is that the rate at which fossil fuels are burnt and the rate at which the stock of carbon
dioxide in the atmosphere increases in the near term may merit more attention than the total
accumulation of carbon dioxide over the very long term.
Aleklett sees most scenarios for the growth of oil supply, including those employed by the IEA
and the Inter-governmental Panel on Climate Change (IPCC), as over-optimistic, and there was some
support for the view that they tell us more about where demand “would like to go” than where supply
will be able to meet demand.

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20 – SUMMARY OF DISCUSSIONS

6. NON-CONVENTIONAL OIL

Oil can be produced profitably at current prices from a range of unconventional sources. The
Orinoco Belt in Venezuela is estimated to contain 230 to 300 billion barrels of very heavy crude oil.
This is around the size of Saudi Arabia’s oil reserves. Canada holds a similar amount of very heavy oil
in its tar sand deposits in Alberta. Both deposits are already in production and profitable at prices
above $40/bbl. Extraction is expanding rapidly, and the main constraints are environmental, nottechnological. Canada produced 1M bbl/day in 2005 and expects to produce 2M bbl/day in 2010. The
USA, Russia and the Middle East also have large tar sand deposits.
Oil shales hold even larger quantities of potentially recoverable oil, estimated at around
3 000 billion barrels. There are deposits in many countries with large quantities located in the USA,
Russia and Brazil. Oil shale is used to fire power generation in a number of countries. It would
probably be profitable to produce oil from shale at current prices with currently available technology.
Costs would fall substantially with expansion of production.
Coal has been converted to oil by SASOL in South Africa since 1955 and China is currently
building two South African designed plants. There are large coal deposits in a wide range of countries
around the world4, with the USA holding the largest reserves. 2007 saw several bills presented to the
US Congress for subsidies to finance coal to liquid fuel plants. Operating costs for such plants arecovered at oil prices above $40/bbl.
If these non-conventional sources hold the promise of very large quantities of oil to be produced
at today’s prices they pose serious environmental challenges. Extraction and processing into refinery
grade oil requires a lot of extra energy, resulting in more than twice the CO2 emissions associated withconventional oil (Greene 2007). Because of this, the potential of using nuclear power to provide
process energy is being considered for Canadian tar sands. Stripping the forest and soil coveroverlying the Canadian tar sands deposits also releases large amounts of greenhouse gases. Productionof shale and coal requires large amounts of water, and many of the potential mines are in areas withwater resources under stress.
Carbon capture and storage might be employed to reduce the CO2 emissions associated with tar
sand and shale oil production to levels closer to conventional oil but it is as yet an unproventechnology. It is difficult to envisage a large scale retrofit programme in Venezuela and Canada if itwere to prove viable. Coal-to-liquid fuel production is somewhat more suited to carbon capture as the
Fischer-Tropsch process employed produces a very pure waste stream of carbon dioxide.
Aleklett argues (Aleklett 2007b) that applying a peak-oil type analysis to coal and nonconventional oil reserves demonstrates that there are insufficient hydrocarbon resources to produce theCO2 necessary to increase concentrations in the atmosphere to the levels envisaged by the InterGovernmental Panel on Climate Change (IPCC). The majority of participants at the Round Table,
however, viewed greenhouse gas emissions rather than oil supply shortages as the key long term issue
for oil demand from the transport sector. At the same time, as governments begin to develop policies
to guard against catastrophic climate change despite large uncertainties in climate modeling, theOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 – © OECD/ITF, 2008

SUMMARY OF DISCUSSIONS -21

precautionary principle suggests they might give similar consideration to peak-oil arguments despite
uncertainty over the extent of their conservative bias.

7. DOES A PRICE OF $100 A BARREL OF OIL MATTER?

Oil price shocks destroy demand for oil and have repercussions for activity across the economy.
They reduce economic activity to the extent that short run substitution and efficiency responses areunable to prevent the cost of production of goods and transport services rising to levels that exceed thewillingness of consumers to pay for them. This reduces economic output and results in businessfailures and unemployment.
In the 1970s, OECD economies were highly vulnerable to external shocks because of widespreadgovernment intervention in prices and rigidities in labour and financial markets. Growing inflation
meant a sharp downward adjustment was probably inevitable, and this was precipitated by the 1973 oilembargo. Many of the immediate responses of OECD governments exacerbated the crisis: additional
price controls on domestic oil production in the USA; restrictions on domestic oil production topreserve resources in Canada.
Today, OECD economies are much less oil intensive and exhibit fewer rigidities. OECDeconomies are not exposed to inflation (although it is rising) and markets are much freer to adjust tochanges in energy prices. The countries where oil prices are determined by governments rather thanmarkets lie in the Middle East and Asia, including China, with artificially low prices one of the factors
contributing to strong growth in oil demand in these developing economies. More generally, incomes
have increased substantially in most parts of the world and energy costs account for a smaller part ofdisposable income. Most of the world’s economy is therefore much more resilient to price shocks thanit was in the 1970s.
The current low level of the dollar against other major currencies is also significant, as oil prices
are quoted in dollars throughout the world. The dollar was trading at 0.68 euros in November 2007
compared to 0.99 euros in January 2000, i.e. one third lower. The price for crude oil in euros is thus
only two thirds what it might have been if dollar parity had been maintained over the period of steadyoil price increases since 2000. Though the yen/dollar exchange rate has only moved 8% since 2000,
compared to 1973 the Japanese yen is now worth three times what it was in dollars.
For all these reasons the economic impact of $100/bbl oil is much less than it was in 1979. Thatsaid, some economies will feel the effects of today’s high oil prices more than others will. US
consumers have experienced a bigger impact on prices, especially for transport fuels, because oil is
priced in dollars and because excise taxes are a relatively small part of prices at the pump compared tomost other OECD countries.
If high oil prices eventually contribute to an economic slowdown in the USA, imports from China
will fall. China’s growth is highly dependent on its exports, and the USA accounts for the largest partof its trade by volume, although the weak dollar has put Europe in first place in trade by value(Financial Times 10.12.2007). China is also exposed to high international oil prices because thegovernment controls domestic oil product prices at levels currently below cost. It will be forced to pay
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22 – SUMMARY OF DISCUSSIONS
refiners large sums in compensation so long as prices stay high. This combination of factors could
contribute to falling prices in the next few years.

8. TRANSPORT SECTOR RESPONSES TO CHANGES IN OIL PRICESTransport is the one sector of the economy where substitution with other fuels has been
negligible. Consumer responses to changes in fuel prices are often measured through elasticities.
There is considerable agreement that the price elasticity of fuel demand is fairly low, meaning thatprices have no big impact on demand – but “no big impact” is different from “no impact”. The longrun elasticity of fuel demand has historically been in the range of -0.4 to -0.6. Since the absolute valueof the elasticity is below one, fuel consumption declines when prices rise but expenditures increase.
The resulting shifts in allocation of expenditure to travel from other goods and services depress
consumption in other parts of the economy, and result in a transfer of wealth to domestic and foreign
oil producers.
Higher fuel prices affect fuel demand through two main channels. First, consumers respond by
driving less. Second, they invest more in fuel economy, i.e. in more fuel efficient vehicles. Recent
evidence for the US (Small and Van Dender, 2007) suggests that the relative importance of those two
effects has changed as incomes increased: the responsiveness in terms of reduced driving has become
substantially smaller, so that a bigger share of the total response comes through improved fueleconomy.
Note that smaller responses in terms of driving imply a more limited overall fuel price elasticity
of demand, around -0.24 instead of -0.36 for the US in 2000-2004; and price effects are counteracted
by the income effect, which implies growing consumption as incomes rise.
It should be emphasized that elasticities of demand refer to consumer prices of fuel. Gasoline anddiesel are taxed at much higher rates than oil products for use in other sectors, especially in Europe
and Japan. Prices for gasoline after tax currently equate to over $300/bbl in many European countries.
The higher consumer prices in Europe and Japan are one reason why elasticities in these parts of theworld may be higher than those in the US. Another reason is that more European and Japanese drivers
have access to alternative transport modes than US drivers. Slightly lower real incomes contribute tohigher elasticities as well. On the other hand, more US households have access to several vehicles,
providing the opportunity to switch to a more fuel efficient vehicle when oil prices are high. Althoughdifferences in elasticities between the US and Europe or Japan are likely to be small, it will not be
entirely clear that the finding of declining elasticities in the US is transferable to other countries
without empirical studies in those countries.
Freight transport is less affected by oil price increases than private car use as fuel accounts for
only a small part of the total cost of producing most goods. Salaries, vehicles and tax are larger itemsof expenditure than fuel for transport companies. In France it is estimated that the cost of crude oilwould have to increase eight fold to double the cost of road freight transport (Chevroulet 2007). The
difficulty for freight transport companies is primarily the delay in passing on fuel costs to clients inperiods when prices rise rapidly; contracts cover extended periods and do not always provide for fuelcosts to be passed on until renegotiation of the contract itself.
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9. MOTIVATING TRANSPORT POLICIES – MARKET FAILURES

Transport generates a range of social costs that are not taken into account by consumers or firms
when they decide on how much and what kind of transport to use. Such external costs sometimes
justify policy intervention because market outcomes are less than optimal. The main external costs are
related to accidents, climate change, congestion and local air pollution. Some of these costs(e.g. congestion) are fairly well understood and relatively accurately measured. Others, notably thecosts of climate change, are poorly understood and their measurement continues to generatecontroversy.5
Debate at the Round Table highlighted the substantial uncertainty about the future availability ofoil and the prices at which it will be sold. Part of the price uncertainty relates to OPEC’s market
power. But are uncertainty and import-dependency a basis for government intervention in energy ortransport markets?
Uncertainty is pervasive throughout the economy, and not in itself a source of market failure. Aslong as both firms and consumers make decisions on the best available information markets respond
optimally to uncertainty. Despite large uncertainties, oil companies do invest in exploration andproduction and in refinery capacity. The clearest rationale for government intervention is thus ensuringhigh quality information is widely available.6
Oil dependency is primarily an issue of market power. Concentration of oil production in thehands of a cartel that explicitly aims to control prices is a clear case of market failure. Despite
government and private sector efforts to diversify sources of oil supply, concentration of market powerin the Middle East is expected to grow rather than diminish.
There is also an externality dimension to oil dependence. The USA is a very large consumer andimporter of oil so probably enjoys a degree of monopsony power on the world oil market; lower US
demand reduces world prices. Individual US consumers ignore this effect when deciding on theirpurchases of oil and of vehicles and other oil consuming equipment. This potential monopsony effectis therefore external to the market. Without government intervention its potential benefits will beforegone.
Another dimension to oil import dependency is the transfer of resources from importing toexporting countries. In strict economic terms transfers are not of particular concern because oilrevenues will eventually be recycled to the oil importing countries through purchases of goods andservices and through investment. But with high oil prices the transfers are very large, politically highly
visible and they can create large temporary imbalances.
Policies to reduce market power through oil substitution and fuel efficiency are the most relevant
responses to oil dependency although it would be possible to transfer some of the economic rent fromoil production to the importing countries through additional taxes on oil product consumption, albeit at
the risk of pushing prices even higher.

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24 – SUMMARY OF DISCUSSIONS

10. POLICY INSTRUMENTS

Fuel excise duty and carbon tax
Excise duty on transport fuels is widely used in OECD countries as a reliable source ofgovernment income because of the relatively low price elasticities of demand. The overall effect on oil
prices of simultaneous attempts by OPEC to maximise its profits and by oil importing countries toincrease fuel taxes is not easy to predict. It is conceivable that higher fuel taxes in the USA would
increase welfare if accompanied by reductions in taxes on labour and capital. In addition, such tax
increases would reduce some of the rent from oil production accruing to oil exporting countries,
because reduced consumption in the USA eases pressure on world prices. Note that at present thereverse situation applies. Fuel excise taxes have been stable in nominal terms in the US and manyother OECD countries for the last 5-10 years, eroding their value in real terms.
A number of governments have responded to oil price increases with small cuts in fuel excise tax.
The potential to shield consumers in this way is, however, limited by the size and the duration of the
impact on government finance. It is also counterproductive as it reduces incentives for fuelconservation and dampens consumer response to oil price increases. Not only does this interfere withthe response, it also reduces the price elasticity operating on the oil exporting countries and thusincreases their market power.
Governments are not likely to increase fuel taxes when oil prices are rising as this would
exacerbate the short run impacts of high oil prices. It might, however, be possible to increase excise
taxes when prices fall.
A tax on carbon would have a very similar effect to fuel excise duty in transport markets, as noncarbon based fuels are not likely to gain a large market share soon. The main difference is that a
carbon tax would apply equally to all sectors of the economy whereas current taxes on oil products
differ enormously between sectors. For example, domestic heating oil is normally taxed at very low
rates in comparison to auto diesel, which is a very similar product, just put to a different use. Tax
subsidies for diesel compared to gasoline would also disappear, as on a volumetric basis diesel would
attract a slightly higher carbon tax than gasoline.
A Pigouvian carbon tax to internalise the social costs of CO2 emissions, applicable at the samerate to all sectors of the economy and applied in a large number of countries, would be the mostefficient policy response to the threat of climate change. Setting the rate for such a tax is a political
exercise because of the very real uncertainties in estimating the costs of climate change through its
physical impacts on sea level and the weather and consequent effects on crop production, river flows,
ecosystems, health and the frequency and intensity of natural disasters related to the weather. Proxies
have been calculated from the expected costs of expenditures to reduce emissions to rates that would
stabilise the accumulation of CO2 in the atmosphere at a level believed sufficient to avoid catastrophic
climate change. The most influential recent report on climate policy, the Stern Report (Stern 2006),
estimated total damage costs from future warming at 5-20% of world GDP in perpetuity andrecommends a current social cost equivalent to $311 per ton of carbon (Euros 60 per ton of CO2)OIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 – © OECD/ITF, 2008

SUMMARY OF DISCUSSIONS -25

according to calculations by Resources for the Future (Harrington et al., 2006). This is much larger
than some other values frequently employed, such as the average level of trading for carbon permits inthe second session of the European Trading System (around Euro 20 per ton)7 but it is still much lower
than the level of fuel excise tax in any European country. For example, UK fuel excise duty, at the topof the range in Europe, of Euros 0.70 per litre equates to Euros 304/ton CO2 for gasoline and Euros
270/ton CO2 for diesel; French excise duty on gasoline of Euros 0.60 per litre equates to Euros 259/ton
CO2 and excise duty on diesel of Euros 0.43 per litre equates to Euros 163/ton CO2.

Table 1. Fuel tax rates and shadow prices for CO2

Tax / Valuation

Euros / ton CO2

ETS trading price20

US gasoline tax

37

US diesel tax

37

Stern Report valuation60

French diesel tax

163

French gasoline tax

260

UK duty: diesel

270

UK duty: gasoline

304

This begs the question of what fuel excise duties are for. In the USA federal fuel duties areearmarked for the Highway Trust Fund, which finances road and transit projects, and which sees real
revenues declining because of falling real gas taxes. Fuel taxes are not hypothecated in most othercountries, but instead contribute to general revenue. As long as sophisticated road-pricing systems are
the exception rather than the rule, a reasonable system of road charges would see the fixed costs ofroad provision covered from general revenue8 and the variable costs of road use paid through variablecharges, such as fuel tax. The variable costs include road maintenance (as far as related to use and not
the weather) and the external costs of greenhouse gas emissions, local air pollution, accidents andcongestion9. In high fuel excise tax countries such as the UK research has estimated that charges
currently roughly balance costs, even if there are mismatches in their differentiation by type of
vehicle, location and time of use (Sansom 2001). Parry and Small (2005) found UK fuel taxes to be
too high and those in the US too low, taking this “second-best” approach to relating fuel taxes toexternal costs.
At the same time, most studies of the external costs of road use find CO2 emissions to be small
relative to other types of externality, especially congestion (Figures 3 and 4). This is not to say that thecost of climate change is not large, rather there are other more pressing market failures in transport.

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26 – SUMMARY OF DISCUSSIONSTaxes on transport fuels can perform three functions:

The Pigouvian objective of internalising external costs;



The Ramsey objective of providing public revenues in the least allocatively distortingmanner. Since fuel taxes are changed in a context of pre-existing taxes, the relevant concern
here is how the change exacerbates or relieves the allocational distortions of these preexisting taxes. Labour taxes are particularly distorting, so the issue becomes whether higher
fuel taxes lead to higher or lower real wages, and this depends as much on how revenues areused as on the tax change itself;

A distributional objective by attempting to transfer rents from governments in oil exporting
countries to governments in net oil importing countries.



If a fuel excise duty were to be employed to achieve all three objectives, how should its rate
be set? In general, this depends on the weights given to the various functions, which in turnreflects policy objectives. When government cares strongly about revenues, high fuel taxes
seem justified to the extent they offset increases in labour taxes. This may reflect European
practice.
Figure 3. CO2 relative to other external costs (US cents/mile)
40
35
30
25
Climate change

20

Oil dependency
15

Congestion
Air pollution

10

Noise, Water
5

Accidents

0
Low

High

Low

High

(US & Europe)

(UK)

(US)

Harrington-McConnell

Sansom et al.

Parry et al.

Source: Small and Van Dender (2007).

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SUMMARY OF DISCUSSIONS -27

Figure 4. Overview of MC for interurban car travel (Euros per v-km)

Source: Nash (2003).

Vehicle efficiency regulations
In relation to oil import dependency it is not clear from the discussion above that taxation is anappropriate instrument to address either market power or the external benefits of reducing fuelconsumption. Alternative policies to promote fuel efficiency are indicated, primarily fuel efficiency
regulations.
Intervention to promote fuel efficiency is frequently argued for on the basis that consumers
undervalue fuel savings when they purchase cars (and other equipment) because they employ higher
discount rates than socially optimal (their planning horizon is shorter than that of the government).
Consumers make decisions on how much fuel economy to buy in a context of combined uncertainty
and risk aversion. This leads to lower fuel economy compared to a risk-neutral environment but is notin itself a market failure if we assume consumers are adequately informed of the cost of running a car(and there is a wealth of car magazines available to inform car buyers on this point). However, there isa case for government intervention effectively to substitute a social discount rate for the shorter,
typical private discount rates applied by consumers in making decisions on car purchase.
Regulatory emissions limits have been employed fairly successfully to address local air pollution
externalities. They can also be employed in the case of CO2 emissions and equivalent regulations wereintroduced in response to the oil price rises of the 1970s in the USA as Corporate Average Fuel
Efficiency (CAFE) regulations.

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28 – SUMMARY OF DISCUSSIONS
Compared to a pure carbon tax, regulations have the drawback that they are sector specific andtend to favour one technology over another according to the level at which they are set and the way inwhich they are measured. Regulations have to be designed carefully to avoid perverse effects. For
example, differentiating CO2 emissions standards according to vehicle class or weight in an attempt to
avoid one manufacturer facing higher costs than another can provide perverse incentives that favour
high emission vehicles. This was the case with the US CAFE regulations in force until 2007, where
weaker standards for light trucks were instrumental in stimulating a shift in demand from conventionalcars to SUVs. Curvilinear rather than stepwise differentiation can reduce the problem, but can still
reduce incentives for cutting emissions through weight reduction – where there is a large, relatively
low cost potential for savings (see Plotkin 2007 and OECD/ITF 2008 for a more detailed discussion).
Differentiation according to vehicle “footprint” (wheelbase x axle width) is a somewhat less distorting
approach because there are larger costs for manufacturers associated with changing wheelbase.
Allowing weight to increase can actually cut costs. Other constraints also make it difficult to increase
vehicle footprint, for example the size of typical parking spaces in underground garages and multistorey car parks.
Regulations also entail monitoring and enforcement costs that are avoided with simple taxes.
Regulations do, however, have some advantages compared to taxes, not least in terms of politicalacceptability.
Using a standard instead of a tax also has the advantage of reducing uncertainty for vehicle
manufacturers in the sense that they can be relatively certain how both consumers and competitors will
respond to a standard, compared with much larger uncertainty under a tax policy. This certainty
facilitates the large investments required to introduce new generations of fuel efficient technologies.
Regulatory standards for CO2 emissions are undermined to some extent by the rebound effect. By
reducing average fuel consumption they reduce the costs of driving, other things being equal, which
will provide an incentive to drive more often and further, partially off-setting the impact of theregulation. To correct for this effect it is possible to combine regulatory standards with a carbon tax
designed to compensate for the fuel cost savings otherwise engendered by the standard. A combinationof vehicle standards and carbon tax is also indicated as regulations alone risk simply postponing
emissions of CO2 rather than restricting the ultimate quantity of CO2 emitted from the world’s stock of
crude oil to an acceptable (efficient) level, which a Pigouvian tax should achieve if the price can bebased on reasonably accurate damage estimates.
A note of warning was sounded at the Round Table, however, over combining too many
instruments to achieve greenhouse gas mitigation and oil security objectives. A proliferation of
instruments results in a lack of transparency and difficulty in tracing the effects of interventions andincreases the cost of implementation and enforcement, ultimately undermining cost-effectiveness. This
does not rule out using complementary instruments but underlines the need to understand howtransport, environment and energy policies interact. Effective and efficient combinations of
instruments are examined in a companion publication (OECD/ITF, 2008).

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11. DESIGNING TRANSPORT POLICIES: THE NEED FOR INTEGRATING
TRANSPORT, ENVIRONMENT AND ENERGY DIMENSIONS

There are potential trade-offs to be made in addressing the failures that affect oil and transport
markets. The current structure of oil supply, with production concentrated in the hands of a cartel,
suppresses oil demand and in this respect contributes to mitigating CO2 emissions. Some policies to
weaken OPEC market power and reduce oil prices could undermine policy towards climate change.
Promoting non-conventional oil, through subsidies for oil shale or coal-to-oil plants, as demanded
by a number of bills presented to the US Congress in 2007, could reduce OPEC market power if alarge enough part of US oil supply was provided from these plants but it would massively increase
CO2 emissions. It should be noted that with non-conventional oil production on a smaller scale, OPEC
would continue to control prices and the non-conventional oil would be priced at the level of OPEC
oil. Support for non-conventional oil would simply represent a transfer of resources from US taxpayers and oil consumers to oil shale and coal-to-oil producers.
Transport, oil and environmental policies also interact in more subtle ways. Fuel specifications
have played a significant part in the costs of oil refining, the availability of oil products and the priceof oil products in recent decades. For example, California’s fuel specifications related toenvironmental protection isolate the local market from world oil products markets. Local refiners
enjoy the protection that this provides and gasoline trades in Singapore at $10/bbl below the wholesale
price in California. Mismatches in product standards fragment markets and even if the effect is not as
marked in other parts of the world this adds significantly to oil product prices everywhere.
Environmental regulations have sharply reduced the sulphur content of gasoline and diesel toreduce tailpipe emissions of sulphur dioxide, particulates and CO2. Current engine technologies
increase NOx emissions when optimized to reduce fuel consumption. This requires NOx reduction
catalysers for the exhaust that are extremely sensitive to sulphur poisoning. Stripping sulphur out of oilat the refinery requires a lot of energy, resulting in additional emissions of CO2 from the refinery itself.
The balance in CO2 gains and losses between car exhaust pipe and refinery emissions is shifting assour (high sulphur) crudes account for an increasing share of the refining slate. Demand for low
sulphur diesel is one of the factors promoting production of biodiesel in Europe, as it is completely
free of sulphur. Current biodiesel production may be associated with an increase rather than a decreasein greenhouse gas emissions compared to conventional diesel, taking into account N2O emissions fromthe cultivation of feedstocks (OECD/ITF 2007).
Two thirds of the progress in reducing CO2 emissions from new cars in the EU since thevoluntary agreements with car manufacturers entered into force (in 1998) have been the result of ashift from gasoline to diesel engines facilitated by lower fuel taxes on diesel than gasoline. This has
seen diesel consumption rise inexorably and it now outsells gasoline in Europe. The shift has created alarge imbalance in Europe’s refining industry, with excess gasoline sold to the USA and diesel
imported from Russia. This has implications for CO2 emissions as well as prices. Crude oil contains a
mixture of different hydrocarbons. The mix of useful products that can be separated out with minimalenergy input is determined by the nature of the crude. There is a degree of flexibility in the productmix produced, but shifting the mix requires large amounts of additional energy input. An increasing
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30 – SUMMARY OF DISCUSSIONS
number of refineries in Europe convert heavy fuel oil (for which the market is weak most years) into
diesel, but at the cost of additional CO2 emissions from these refineries. The diesel-gasoline balancehas been pushed to its limits in world refining markets. If the US government were to adopt policies topromote diesel cars10 diesel prices would rise significantly and CO2 emissions would increase asadditional crude oil, with deeper conversion processing, would be required to supply the market. It
would not be possible to achieve the European degree of dieselization in any other major car market.
Regulatory standards or taxes intended to internalise the costs of greenhouse gas emissions thus
need to be designed not only to avoid bias towards promoting particular technologies (in this casediesel engines) but also to avoid simply shifting emissions from one point (tailpipe exhaust) to another(refinery smoke stacks) and exacerbating other external costs – in this case NOx emissions, as diesel
engines produce higher levels of NOx than gasoline engines and are generally subject to weaker
emissions standards. These are basic tenants for the design of interventions to protect the environment
but they are frequently overlooked in practice. Fuel taxes in Europe that favor diesel clearly fail thetest.

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31

NOTES

1.

US data suggests that with rising incomes, price elasticities for private road passenger transport
have declined. Consequently, there has been a change in the way drivers respond to higher fuelprices, with the vehicle-kilometres driven less sensitive to the price of fuel than the fuel efficiency
of vehicles.

2.

Although the 1973 Arab-Israeli War and subsequent oil embargo was preceded by re-negotiationsof oil concessions and nationalisations of oil companies in the Middle East and Africa, and by
OPEC coordinating oil production tax and price increases in response to a weak dollar.

3.

Known as “backwardisation”.

4.

Though Aleklett believes that coal production, like oil, has peaked.

5.

The consequences of climate change are at best understood in a probabilistic sense. In addition,
since some of the more catastrophic consequences are likely to take place in the far future, thereis the problem of converting these costs to present values. Such conversion inevitably requires
judgments on intergenerational equity, and it was pointed out that the well-known Stern report
implies substantial sacrifices by current generations to improve the welfare of more wealthy
future generations.

6.

While the private sector produces large amounts of oil market information on a commercial basis,the data and analysis of the IEA and of national administrations, such as the EIA in the USA, isessential in providing a complete and authoritative picture. The work of university researchers on
peak oil has been invaluable in improving the understanding of data on oil reserves reported byoil companies.

7.

Note the price is determined by the amount of carbon allowed to be emitted by the participants inthe scheme, currently determined largely on the basis of what they emitted prior to the scheme.
Such “grandfathering” of emissions rights weakens the effectiveness of the system to cut
emissions and illustrates the artificial nature of the price of carbon that results. The EU plans to
reduce the cap on the amount of carbon traded in the system, which will force the price up.

8.

Or possibly from fixed transport charges, such as annual circulation taxes.

9.

Though fuel tax is not the best targeted instrument for some of these costs.

10. Policies adopted initially in Europe to promote producers of diesel engines.

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32 – SUMMARY OF DISCUSSIONSBIBLIOGRAPHY

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Facing the Hard Truth about an Import Decline for the OECD Countries, JTRC Discussion Paper
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Aleklett, K. (2007b), Reserve Driven Forecasts for Oil, Gas and Coal and Limits in Carbon Dioxide
Emissions: Peak Oil, Peak Gas, Peak Coal and Peak CO2, JTRC Discussion Paper 2007-18,
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http://sres.ciesin.org/; series: http://sres.ciesin.org/final_data.html
OECD/ITF (2007), Biofuels: Linking Support to Performance – Summary and Conclusions,
OECD/ITF, Paris. http://www.internationaltransportforum.org/jtrc/RTbiofuelsSummary.pdf
OECD/ITF (2008), The Costs and Effectiveness of Policies to Reduce Vehicle Emissions – Summary
and Conclusions, OECD/ITF, Paris.
Nash, C. (2003), Final Report of the UNITE programme (UNIfication of accounts and marginal costs
for Transport Efficiency), European Commission.
Parry, I. and K. Small (2005), Does Britain or the United States Have the Right Gasoline Tax?,
American Economic Review, 95, 1276-1289.
Parry, I., M. Walls and W. Harrington (2007), Automobile Externalities and Policies, Journal of
Economic Literature, 45: 373-399.

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SUMMARY OF DISCUSSIONS -33

Sansom, T., C. Nash, P. Mackie, J. Shires and P. Watkiss (2001), Surface Transport Costs and Charges– Great Britain 1998. ITS Leeds, in association with AEA Technology Environment. Reportcommissioned by the Department of the Environment, Transport and the Regions.
Small, K. and K. Van Dender (2007), Long Run Trends in Transport Demand, Fuel Price Elasticities,
and Implications of the Oil Outlook for Transport Policy, JTRC Discussion Paper 2007-16,
ITF/OECD, Paris.
Stern, N. (2006), The Economics of Climate Change: The Stern Review, HM Treasury, London.
http://www.hm-treasury.gov.uk/independent_reviews/
stern_review_economics_climate_change/stern_review_report.cfm
UNITE (2006) Unification of accounts and marginal costs for Transport Efficiency.

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PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES -INTRODUCTORY REPORTS

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35

PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES -PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING
AND EXPORTING COUNTRIES:Facing the Hard Truth about an Import Decline for the OECD Countries

Kjell ALEKLETT
Uppsala University
andInternational Association for the Study of Peak Oil and Gas (ASPO)
UppsalaSwedenOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 – © OECD/ITF, 2008

37

PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES -39

SUMMARY

ABSTRACT .......................................................................................................................................... 41
1.

INTRODUCTION ......................................................................................................................... 43
1.1 Mission ................................................................................................................................... 43
1.2 Major articles by Uppsala Hydrocarbon Depletion Study Group. ......................................... 43
1.3 Peak oil and today’s society ................................................................................................... 44
1.4 References. ............................................................................................................................. 46

2.

FUTURE DEMAND FOR OIL ..................................................................................................... 48
2.1 Future oil demand forecasts by IEA and EIA ........................................................................ 48
2.2 Oil intensity driven demand ................................................................................................... 48
2.4 References .............................................................................................................................. 51

3.

HOW MUCH OIL HAVE WE FOUND AND WHEN DID WE FIND IT? ................................ 53
3.1 Resources and reserves .......................................................................................................... 53
3.2 Oil fields ................................................................................................................................. 54
3.3 Discovery of crude oil ............................................................................................................ 55
3.4 Discovery of heavy oil ........................................................................................................... 58
3.5 References .............................................................................................................................. 59

4.

HISTORICAL CONSUMPTION AND LIMITS FOR FUTURE CONSUMPTION ................... 60
4.1 Production forecasts based on the depletion model ............................................................... 60
4.2 Production from giant oilfields .............................................................................................. 62
4.3 Production from small oilfields .............................................................................................. 64
4.4 Production from deep-water oilfields..................................................................................... 64
4.5 Production from developments of new oilfields .................................................................... 66
4.6 Production from oil sand in Canada ....................................................................................... 67
4.7 Production of heavy oil from the Orinoco Belt in Venezuela ................................................ 68
4.8 Final production profile and conclusions ............................................................................... 69
4.9 Conclusions for production .................................................................................................... 70
4.10 References .............................................................................................................................. 71

5.

IMPORT AND EXPORT SCENARIOS ....................................................................................... 72
5.1 Importing and exporting countries ......................................................................................... 72
5.2 References .............................................................................................................................. 77

6.

PRODUCTION OF TRANSPORT LIQUIDS WITH CTL AND GTL ........................................ 78
6.1 CTL production ...................................................................................................................... 78
6.2 GTL production...................................................................................................................... 81
6.3 References .............................................................................................................................. 81

7.

POSSIBLE STRATEGIES FOR OIL IMPORTING AND EXPORTING COUNTRIES ............ 82
7.1 References .............................................................................................................................. 85

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40 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES
8.

AWARENESS OF PEAK OIL...................................................................................................... 86
8.1 References .............................................................................................................................. 88

9.

ACKNOWLEDGMENTS ............................................................................................................. 89

ANNEX: STATEMENTS 14 OCT 2005 .............................................................................................. 90
APPENDIX: RESERVE-DRIVEN FORECASTS FOR OIL, GAS AND COAL AND LIMITS OF
CARBON DIOXIDE EMISSIONS ....................................................................................................... 95

Uppsala, September 2007

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PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES -41

ABSTRACT

Statistical trends for oil intensity from individual countries and groups of countries show that an
average increase in GDP of 3% per annum equates to a projected demand for liquids of 101 million
barrels per day (Mbpd) by the year 2030. The following analysis shows that this demand cannot be
fulfilled by production from current reserves and expected new discoveries.
Two models are considered for assessing peaks in oil production: the depletion model (DM), andthe giant field model (GFM). The DM model shows peak oil (the maximum rate of production) in theyear 2011 with 90 Mbpd. Adding GFM we develop a “worst case” scenario of a plateau in production
for the next five to seven years at a rate of 84 Mbpd. A more optimistic case in the “Giant High Case”
scenario is a peak in 2012 at 94 Mbpd. A less steep increase in demand can move the peak to 2018.
Both models show an oil production rate in the order of 50-60 Mbpd by 2030.
The demand for oil from countries that are importers is forecast to increase from current importlevels of 50 Mbpd to 80 Mbpd. Saudi Arabia, Russia and Norway, today’s largest oil exporters, will
experience a decline in their export volumes in the order of 4 to 6 Mbpd by 2030. The projectedshortfall cannot be offset by exports from other regions.
In a business-as-usual case, the shortage of fossil fuel liquids for transportation will be substantial
by the year 2030. The necessary decisions for the economic transformation required to mitigate thisdecline in available oil supply should already have been made and efforts to deploy solutions underway.
We have climbed high on the “oil ladder” and yet we must descend one way or another. It may be
too late for a gentle descent, but there may still be time to build a thick crash mat to cushion the fall.

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PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES -43

1. INTRODUCTION

1.1. Mission
Modern civilization has become increasingly dependent upon oil over the past century, with oil
now recognized as the most important global commodity. Currently the oil and gas industry has evensurpassed agriculture as the world’s single biggest industry. At $70 per barrel, the value of the world’s
crude oil business alone is over $2 trillion/year. However, crude oil is far from uniformly distributed
around the world, and only a limited number of countries are significant producers. This fact divides
the world into oil exporting and oil importing countries. The majority of the OECD countries importoil, and these economies will not function without global security in the oil export market.
Unfortunately, peak oil will create a progressively more insecure export market.
The study contained within this paper will address peak oil and the evolving strategies of oil
importing and exporting countries.

1.2 Major articles by Uppsala Hydrocarbon Depletion Study GroupThe findings in this report are mainly based on research done by Uppsala Hydrocarbon Depletion
Study Group, Uppsala University, Sweden, and the following works will be used as main references:[1.1]

K. Aleklett and C.J. Campbell; The Peak and Decline of World Oil and Gas Production,
Minerals & Energy 18 (2003) 5-20.
http://www.tsl.uu.se/uhdsg/Publications/Minerals&Energy_2003.doc)[1.2]

K. Aleklett; Testimony on Peak Oil, presented before the House Subcommittee on Energy
and Air Quality, Washington DC, USA, December 7, 2005.
http://energycommerce.house.gov/reparchives/108/Hearings/12072005hearing1733/
Aleklett2770.htm[1.3]

K. Aleklett; Oil: A Bumpy Road Ahead, World Watch 19-1 (2006), p. 10, (the article isavailable at http://www.peakoil.net/uhdsg/WorldWatch_2006_Jan.doc)[1.4]

K. Aleklett; Oil production limits mean opportunities, conservation, Oil & Gas Journal, 10431 (2006). http://www.tsl.uu.se/uhdsg/Publications/OGJ_Aug_21_2006.doc )[1.5]

Bengt Söderbergh, Fredrik Robelius and Kjell Aleklett; A crash programme scenario for the
Canadian oil sands industry, Energy Policy, 35-3 (2007) p.1931-1947.

[1.6]

Fredrik Robelius, Giant Oil Fields - The Highway to Oil: Giant Oil Fields and their
Importance for Future Oil Production. Acta Universitatis Upsaliensis 69 (2007)
http://urn.kb.se/resolve?urn=urn:nbn:se:uu:diva-7625, (R. Robelius and K. Aleklett, in
preparation for Energy Policy).

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44 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES[1.7]

Kristofer Jakobsson, Fredrik Robelius and Kjell Aleklett; Oil use and economic growth in
Sub-Saharan Africa: current patterns and scenarios, submitted to Energy Policy (2007),
http://www.tsl.uu.se/uhdsg/Publications.html and Kristofer Jakobsson, Oil Use andEconomic Development in Sub-Saharan Africa, Diploma thesis, Uppsala University UPTEC
F05 000 (2007), http://www.tsl.uu.se/uhdsg/Publications/Jakobsson_Thesis.pdf[1.8]

Kjell Aleklett, Discussion - Peak Oil - a fact of reality, Journal of Petroleum Technology
59-6 (2007). http://www.spe.org/spe-app/spe/jpt/2007/06/DissReply.htm[1.9]

Aram Mäkivierikko, Russian Oil, an estimate of the future oil production and oil export
potential of Russia using the Depletion Rate Model, Diploma Thesis, Uppsala University,
UPTEC ES07 018 (2007), http://www.tsl.uu.se/uhdsg/Publications.html(Aram Mäkivierikko, B. Söderbergh, R. Robelius and K. Aleklett, in preparation for Energy
Policy).

[1.10]

Mikael Höök, Werner Zittel, Jörg Schindler and Kjell Aleklett, A resource-driven forecast
for future global coal production, Submitted to Energy Policy (2007);
http://www.tsl.uu.se/uhdsg/Publications.html

1.3 Peak oil and today’s society
The Association for the Study of Peak Oil and Gas (ASPO) introduced the term “peak oil” in
2001, with Colin Campbell (founder of ASPO) defining it thus:"The term Peak Oil refers to the maximum rate of the production of oil in any area underconsideration, recognising that it is a finite natural resource, subject to depletion."
When the International Energy Agency (IEA) presented the World Energy Outlook 2004
(WEO 2004) the term peak oil was discussed as a possible future scenario. In the summary, the IEA
stated: “Production of conventional oil will not peak before 2030 if the necessary investments are
made.” However, when we look further, we find that in Chapter 3 a peak in 2030 is premised on a
USGS (United States Geological Survey) “mean estimate” of 2 626 billion barrels of remaining
conventional oil. In WEO 2004, the IEA adds the caveat that if this estimate should prove too high,then “the peak of production would come by 2015 or before”. The Uppsala Hydrocarbon Depletion
Study Group (UHDSG based at Uppsala University in Sweden) has shown, in an article discussing
WEO 2004, that oil production of 120.3 million barrels per day in 2030 is improbable [1.11].
Subsequent events and reports have demonstrated the importance of peak oil as a central theme aroundwhich economic development must be discussed.
Between July 2005 and December 2006, the United States Government Accountability Office(GAO) investigated issues related to peak oil and in February 2007 released a report to Congressional
Requesters entitled “Crude Oil – Uncertainty about Future Oil Supply Makes It Important to Develop
a Strategy for Addressing a Peak and Decline in Oil Production” [1.12]. The fact that this GAO study
took nearly two years to be completed shows the seriousness with which US policy-makers treat peakoil.
Furthermore, on October 5, 2005 the US Secretary of Energy, Samuel W. Bodman, requested that
the National Petroleum Council (NPC) undertake a study on the availability of global oil and naturalgas [1.12]. This letter helps demonstrate the political levels that peak oil has now reached:OIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 – © OECD/ITF, 2008

PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES -45“Dear Mr. Raymond,
Perspectives vary widely on the ability of supply to keep pace with growing world demand for oil andnatural gas, the point in time at which global oil production will plateau and then begin to decline(“peak oil”), the implications these may have for the U.S. and world economies, and what steps
should be taken to achieve more positive outcomes.
Accordingly, I request the National Petroleum Council, NPC, conduct a study on global oil andnatural gas supply. Key questions to be addressed in the study may include:•••

What does the future hold for global oil and natural gas supply?
Can incremental oil and natural gas supply be brought on-line, on-time, and at a reasonable
price to meet future demand without jeopardizing economic growth?
What oil and gas supply strategies and/or demand side strategies does the Council
recommend the U.S. pursue to ensure greater economic stability and prosperity?

……..I look forward to reviewing the Council’s proposed study committee and detailed study plan.
Sincerely,
Samuel W. Bodman”

On July 18, 2007, the NPC accepted the report, “Facing the Hard Truths about Energy”, andpresented this to the Secretary of Energy.
December 2005 saw the Swedish Prime Minister, Göran Persson, set up the Commission on Oil
Independence. He asked the Commission to present concrete proposals to reduce Sweden’s
dependence on oil by 2020 and thereby, in this context, significantly reduce the actual consumption ofoil in Sweden. The report from 21 June 2006, “Making Sweden an Oil-Free Society” [1.14], points outthat the peak oil debate in Sweden was the main cause for the appointment of such a commission.
In December 2005, the peak oil discussion had also reached the U.S. House of Representatives
and the Subcommittee for Energy and Air Quality. On December 5, as the only non-American citizen,
the author was called to deliver a written testimony and invited to Capitol Hill for an oralpresentation [1.2].
For obvious reasons, GAO and NPC have concentrated their efforts on the situation in the USA,and before turning to some of the key points in the report it is necessary to place the report in a more
OECD-oriented context. In the USA, oil production peaked in 1970 and since then production has
seen a steady decline. At the same time, with increasing consumption, the USA is becoming more andmore dependent upon imported oil. Within Europe, we witnessed an increase in the production of oil
up until the end of the 20th century, but the new millennium has seen this rate of production start to
decline. Year by year Europe is steadily growing more dependent on imported oil, just as we havealready seen in the USA. Europe is therefore facing the same problems as the USA, outlined in the
GAO and NPC reports.
During the time frame 2008-2030 it is expected that all oil-producing countries within the OECDwill face the same problems as those that the USA and Europe face today. The hard fact is that OECD
countries in general will be more dependent on oil imports in 2030 than they are today.
The outline of this report will concentrate on oil and will have the following structure:

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46 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES-The future demand for oil.
How much oil have we found and when did we find it?
Historical consumption and limits for future consumption.
Import and export scenarios.
Production of transport liquids with CTL (coal to liquids) and GTL (gas to liquids).
Possible strategies of oil importing and oil exporting countries.
Awareness of peak oil.

1.4 References[1.1]

K. Aleklett and C.J. Campbell; The Peak and Decline of World Oil and Gas Production,
Minerals & Energy 18 (2003), pp. 5-20.
http://www.tsl.uu.se/uhdsg/Publications/Minerals&Energy_2003.doc)[1.2]

K. Aleklett; Testimony on Peak Oil, presented before the House Subcommittee on Energy
and Air Quality, Washington DC, USA, December 7, 2005.
http://energycommerce.house.gov/reparchives/108/Hearings/12072005hearing1733/Aleklett
2770.htm[1.3]

K. Aleklett; Oil: A Bumpy Road Ahead, World Watch 19-1 (2006) p. 10.
http://www.peakoil.net/uhdsg/WorldWatch_2006_Jan.doc)[1.4]

K. Aleklett; Oil production limits mean opportunities, conservation, Oil & Gas Journal
104-31 (2006). http://www.tsl.uu.se/uhdsg/Publications/OGJ_Aug_21_2006.doc )[1.5]

Bengt Söderbergh, Fredrik Robelius and Kjell Aleklett; A crash programme scenario for the
Canadian oil sands industry, Energy Policy, 35-3 (2007), pp. 1931-1947.

[1.6]

Fredrik Robelius, Giant Oil Fields – The Highway to Oil: Giant Oil Fields and their
Importance for Future Oil Production. Acta Universitatis Upsaliensis 69 (2007)
http://urn.kb.se/resolve?urn=urn:nbn:se:uu:diva-7625, (R. Robelius and K. Aleklett, in
preparation for Energy Policy).

[1.7]

Kristofer Jakobsson, Fredrik Robelius and Kjell Aleklett; Oil use and economic growth in
Sub-Saharan Africa: current patterns and scenarios, submitted to Energy Policy (2007),
http://www.tsl.uu.se/uhdsg/Publications.html and Kristofer Jakobsson, Oil Use andEconomic Development in Sub-Saharan Africa, Diploma Thesis, Uppsala University
UPTEC F05 000 (2007), http://www.tsl.uu.se/uhdsg/Publications/Jakobsson_Thesis.pdf[1.8]

Kjell Aleklett, Discussion - Peak Oil - a fact of reality, Journal of Petroleum Technology
59-6 (2007). http://www.spe.org/spe-app/spe/jpt/2007/06/DissReply.htm[1.9]

Aram Mäkivierikko, Russian Oil, an estimate of the future oil production and oil export
potential of Russia using the Depletion Rate Model, Diploma Thesis Uppsala University,
UPTEC ES07 018 (2007). http://www.tsl.uu.se/uhdsg/Publications.html(Aram Mäkivierikko, B. Söderbergh, R. Robelius and K. Aleklett, in preparation for Energy
Policy).

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PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES -47[1.10]

Mikael Höök, Werner Zittel, Jörg Schindler and Kjell Aleklett, A resource-driven forecast
for the future global coal production, Submitted to Energy Policy (2007).
http://www.tsl.uu.se/uhdsg/Publications.html[1.11]

Kjell Aleklett, 20040906, International Energy Agency accepts Peak Oil. An analysis ofChapter 3 of the World Energy Outlook 2004.
http://www.peakoil.net/uhdsg/weo2004/TheUppsalaCode.html[1.12]The United States Government Accountability Office (GAO), February 2007, “Crude Oil –Uncertainty about Future Oil Supply Makes It Important to Develop a Strategy for
Addressing a Peak and Decline in Oil Production”. www.gao.gov/new.items/d07283.pdf[1.13]

National Petroleum Council, NPC, “Facing the Hard Truths about Energy”, presented to theSecretary of Energy. http://www.npc.org/[1.14]The Swedish Oil Commission, report from June 21, 2006, “Making Sweden an Oil-Free
Society” (http://www.sweden.gov.se/sb/d/574/a/67096).

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48 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES

2. FUTURE DEMAND FOR OIL

2.1. Future oil demand forecasts by IEA and EIA
In the World Energy Outlook 2004 (WEO 2004), published by the International Energy Agency(IEA [2.1]), the correlation between GDP growth and increases in oil consumption was discussed. The
conclusion was that over a 20-year average an increase of 3% in GDP was correlated with a global
increase in oil consumption of 1.6% per year. Starting with a consumption of 77 million barrels perday (Mbpd) for the year 2002, the demand predicted for 2030 is set to be 121.3 Mbpd, an exponential
growth over 28 years. Previously in WEO 2001, the final year for the forecast period was 2020 [2.2]and in WEO 2002 the IEA added a further 10 years of exponentially increasing demand [2.3] without
considering the implications of peak oil. The next WEO was for 2004 with exponential growth still
being utilised for forecasting purposes. We made an analysis showing that this prediction of
exponential growth was unrealistic [2.4], an analysis which consequently so disturbed the IEA thatthey contacted us and requested that the analysis be removed from the Web. However, the analysis
remained on the Web and in WEO 2005 the increase in demand was reduced to 1.4%, with demand for2030 being reduced to 115 Mbpd [2.5]. This number has since remained the official demand figure for
the IEA [2.6]. The US Energy Information Administration (EIA [2.7]) has calculated a 118 Mbpd
demand for 2030 with OPEC and Non-OPEC production being 57 Mbpd and 61 Mbpd respectively.

2.2. Oil intensity driven demand
The fact that a scaling of GDP is used as a driving force for growth in oil demand has led us tomake a detailed study of the correlation between GDP and oil consumption [1.7]. The standard GDP
measure is calculated from currency exchange rates, a misleading figure in comparisons between
countries, since differences in price levels are not taken into account. The GDP adjusted to Purchasing
Power Parity (PPP) addresses this problem and gives a somewhat more accurate picture of relative
income levels and standards of living. Throughout this study, real GDP (PPP) at constant year 2000
prices has thus been used instead of unadjusted GDP.

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PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES -49

Figure 2.1. Oil use versus GDP (PPP) per capita in 2004 for all countries with available data
40000

GDP (PPP) per capita 2004
(year 2000 $)

35000
30000
25000
20000
15000
10000
OECD countries
Other countries

5000
0
0

50

100

150

200

Oil use per capita 2004 (GJ/year)

The size of a circle represents population size. A number of small countries, among which
Luxembourg, Singapore, Kuwait and Qatar, have too large an oil consumption to be shown in thegraph. The OECD countries are shown as hatched circles and Turkey has the lowest number.
To understand how important oil is for GDP we show in Figure 2.1 the correlation between GDP
per person and oil consumption by person. The size of the circle is related to the population in the
country. There is no doubt that GDP and oil consumption are strongly correlated. No country has
attained a GDP similar to OECD Europe without a significant increase in oil consumption.
Presumably, this also applies to Turkey and other countries striving for higher GDP. Historically,
countries at the top of the list, like the USA, have used more than a one-to-one correlation foreconomic growth. For today’s expanding economies like China and India, we have a one-to-one
correlation [1.7].
Based on the supposition that GDP is the primary driver of oil demand, a simple model of oil
demand can be formulated:
Eoil = (Eoil/GDP) * GDP (1)where Eoil is the total demand of energy from oil, and (Eoil/GDP) is a factor henceforth labelled “oilintensity” (OI). OI is in itself a function of a number of factors such as technical efficiency, thestructure of GDP, and the relative importance of oil as a primary energy source. Thus, treating OI as astraightforward measure of ‘efficiency’ in oil use, as is done occasionally, is misleading. OI is affectedby several factors unrelated to efficiency. Constructing a scenario of oil demand using equation (1)only requires scenarios of GDP and OI, respectively.

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50 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES
Figure 2.2. Development of oil intensity (OI) in selected countries, 1980-2005 [1.7]
9

RussiaOil intensity (MJ per $ GDP (PPP))

8

United States
7

Sweden

6

Japan

5

FranceGermany

4

UnitedKingdom
Brazil

3

China

2

India

1

SSA
20
05

20
00

19
95

19
90

19
85

19
80

0

Figure 2.2 shows the development of OI in selected countries for 1980-2005: Sub-SaharanAfrica, SSA, representing a region without any growth per capita in GDP; China and India with strong
growth in GDP; Russia as a transition economy; and some OECD countries.
Four observations can be made:••••OI has tended to converge towards a common level over time.
Countries with initially high OI, e.g. the United States, Russia, Japan, France, China andSweden, have declined dramatically.
Most of the decline in OI took place during the first decade of the period, 1980-90, while
subsequent decline has been much less dramatic (except in the case of Russia).
Despite declining OI in OECD countries, they are still more oil-intense than India has been
throughout the period. SSA also appears to maintain a rather low OI by international
standards.

The last observation is perhaps counterintuitive. The OECD countries, despite their shift towards
service economies, access to various alternative energy sources, technological capabilities, andoccasionally explicit policies of reduced oil dependence, have not managed to become less oil intensethan the developing economy of India. The radical decline in OI that occurred in several countries
after 1980 may be interpreted as a response to the record high oil prices of the second oil shock.
Conspicuous, though, is that no such price response is visible in SSA, India and Brazil, countries at an
already low level of oil intensity. More recently, India has been suspected of underreporting its oil
product imports [2.7], which makes it difficult to determine whether the decline in OI observed since
2002 is actually genuine.
The bottom line conclusion is that no OECD country has developed an economy that functions at
a lower oil intensity than that of India. Regarding the oil intensity of India as the lower limit for theforeseeable future, it is possible to make a scenario of world oil demand based on the future
development of oil intensity.

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PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES -51

Figure 2.3. Oil intensity for OECD countries and non-OECD countries
compared with the oil intensity of India

In our forecast we assume that the whole world will have the same oil intensity as India in year 2030.
Starting in 2010 the oil intensity for OECD countries has to decrease by 3.2% per year and for the
non-OECD countries by 2.7% per year.
If we look at the oil intensity in the OECD and non-OECD countries and compare it with India, it
is obvious that the world economy has to be less oil intense. The annual decrease for OECD has to be
3.2% and for non-OECD 2.7%. New technologies, savings, changes of life style, etc., are needed, but
let us assume that these are all possible.
In our scenario we assume that the future global increase in GDP of 3% is divided in such a waythat OECD countries take 2% and non-OECD 5%. With these numbers, equation 1 will give a demandof 101 Mbpd. This value is 14 Mbpd lower than the IEA forecast and 17 Mbpd lower than the EAI
forecast, but we should remember that the cut in oil intensity for most of the countries in the world is avery tough mission.

2.4 References[2.1]

International Energy Agency, IEA; World Energy Outlook 2004;
http://www.iea.org/textbase/nppdf/free/2004/weo2004.pdf[2.2]

International Energy Agency, IEA; World Energy Outlook 201;
http://www.iea.org/textbase/nppdf/free/2000/weo2001.pdf[2.3]

International Energy Agency, IEA; World Energy Outlook 2002;
http://www.iea.org/textbase/nppdf/free/2000/weo2002.pdf

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52 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES[2.4]

Kjell Aleklett, IEA accepts Peak Oil - An analysis of Chapter 3 of the World Energy Outlook
2004, November 2004,
http://www.tsl.uu.se/uhdsg/Publications/AnalysisWorldEnergyOutlook2004.pdf[2.5]

International Energy Agency, IEA; World Energy Outlook 2005;
http://www.iea.org/textbase/nppdf/free/2005/weo2005.pdf[2.6]

International Energy Agency, IEA; World Energy Outlook 2006;
http://www.iea.org/Textbase/publications/free_new_Desc.asp?PUBS_ID=1929[2.7]

Energy Administration Information, EAI, International Energy Outlook 2007, May 2007;
http://www.eia.doe.gov/oiaf/ieo/pdf/0484(2007).pdf

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3. HOW MUCH OIL HAVE WE FOUND AND WHEN DID WE FIND IT?

The oil production process is based upon the development of oil fields that were originallylocated by the exploration of potential geological structures. The United States Geological Survey(USGS) has made detailed studies of where conventional oil resources can be found around the world[3.1] and, with the exception of regions around the North Pole, we can conclude that oil companies
have been and are looking for oil in all of these regions. When discussing future oil production, it
should be further noted that the oil industry is a mature industry, lacking the naiveté of less matureindustries.

3.1 Resources and reserves
To better understand how much oil has been found and when it was found, a short review of thevarious classifications of oil resources and reserves is required. Original resources are the total amountof oil that originally existed in the Earth’s crust. Among the original resources that have been
discovered, some are recoverable and some are unrecoverable. Every oil field has a specific recovery
factory that is dependent upon the geological condition of the reservoir, but is also affected bytechnical solutions used in each oil field’s production.
The discovered, recoverable resources are referred to as the Ultimate Recoverable Reserves,
URR, being the sum of cumulative production and production from reserves. The discovered,unrecoverable resources are divided into technically recoverable but not economic resources, andunrecoverable resources that are neither technically recoverable nor economic. Future production ofoil is therefore dependent on today’s reserves, future economic reserves, and undiscovered oil that canbe converted into economic reserves.
However, there is always uncertainty about how much oil in an oil field can actually berecovered. This uncertainty has led to the calculation of reserve figures based upon the probability of
extraction, the confidence of recovering a given amount of oil from a given oil field. A reserve
estimate followed with, for instance, “P90” means that there is a 90% chance that there is at least as
much recoverable oil as the reserve estimate claims.
In addition, industry makes the following division of reserves:a. Proved reserves: can be estimated with a high degree of certainty to be recoverable. It is likelythat the actual remaining quantities recovered will exceed the estimated proved reserves.
Proved reserves are labelled 1P.
b. Probable reserves: additional reserves that could be recovered but with less certainty thanproved reserves. It is equally likely that the actual quantities recovered will be greater or lessthan the sum of the estimated Proved + Probable reserves. This sum is labelled 2P.

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c. Possible reserves: additional reserves that are less certain to be recovered than probablereserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of
the estimated Proved + Probable + Possible reserves. This sum is labelled 3P.
Understanding published statistics of reported reserves is difficult because some publications
report only 1P reserves, others report 2P reserves, and yet others report a mixture of 1P, 2P or even 3P
reserves [3.2].
As an example, let us take the reserves in Saudi Arabia, and for the purposes of this discussion
we will use the data presented by Mahmoud M. Abdul Baqi and Nansen G. Saleri from Saudi Aramco
at a presentation in Washington D.C. on February 24 [3.3].
Oil-in-place (OIP) is the estimated total amount of oil that is in the ground before production has
started, and OIP for Saudi Arabia is reported to be 700 billion barrels (Gb) (the number 720 Gb has
been recently reported in some newspapers). The total production so far is 105 Gb or 15% of the
700 Gb of OIP. The 2P reserves were claimed to be 260 Gb, or 37% of OIP. If we add the fraction
produced and the fraction in reserve we obtain a recovery factor of 52% on average for all of the
one hundred oilfields in Saudi Arabia.
Leif Magne Merling from Statoil has made a study of recovery factors for thousands of oilfields
and in 2004 he reported the average global recovery factor as 29% (and technology may increase thisfigure to 38% in the future) [3.4]. The P1 number for Saudi Arabia has been reported as 131 Gb, or
19% of OIP [3.3]. This number combined with the produced figure gives a recovery factor of 34%,
which is already over the average reported currently.
In the 1980s, the reserves in OPEC countries were reported to have increased by 300 Gb [1.1],
even though new discoveries had not been made. We can then treat these increases as new estimates ofrecovery factors, but the question remains: “can these new high-recovery factors be sustained?” Whenit comes to planning future liquid production for transport, we should not simply accept this as fact.

3.2 Oilfields
Oilfields come in many different sizes, and of the total number of oil fields in the world,
estimated at 47 500, only 507 are considered to be giant oilfields. The definition of a giant oilfield is
one that will ultimately produce more than 500 million barrels (Mb) of oil. Uppsala Hydrocarbon
Depletion Study Group has made an extensive study of giant oilfields, presented in the thesis ofFredrik Robelius [1.6]. Data and information on giant fields has been collected in a database named“Giant Field Data”. This database includes information on discovery year, year of first production,
cumulative production up to 2005 and different URR (Ultimate Recoverable Reserves) estimates.
In this study by the UHDSG, the measure of the size of an oilfield (from which the designation
giant is derived) proved to be important and the measure chosen was the URR. Previously, URR was
defined as the cumulative production plus the recoverable reserves. Yet the phrase “recoverable
reserves” represents a highly dynamic value that consequently affects the URR. In order to minimize
the impact of this dynamic aspect of URR, proven plus probable (2P) reserves were used in the study.

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The many different estimates for URR over the last ten years lie in the range of 1 750 to 2 850 Gb.
One reason for this wide variation is the diverse types of oil included in the various estimates where, forexample, some will include oil sands but other estimates are confined to conventional oil. Moreover, theestimates include oilfields “yet to find in the near future” and obviously this “yet to find” part of theestimate is uncertain, with much controversy revolving around this figure.
An average of the estimates from the last ten years gives a URR value of 2 250 Gb and a similarvalue is obtained by adding the approximate 1 000 Gb produced to date to the IHS Inc. energy estimateof a remaining 2P reserve of 1 200 Gb [3.10]. According to our database, the URR of the 507 giant oilfields is estimated at between 1 150 and 1 550 Gb; thus, if using 2 250 Gb as a global value of URR,
giant fields represent about 55% of the global URR. Giant fields have obviously dominated past
production, and future production will continue to be dependent upon these giant oilfields.

3.3 Discovery of crude oil
To estimate how much oil can be produced in the future we need to know how much has beenfound, when in time it was found, and how much we can expect to find. Every year, the publications
Oil & Gas Journal [3.5], BP Statistical Review of World Energy [3.6] and World Oil [3.7] report thefigures for production of oil, consumption of oil and oil reserves. The year-by-year calculated
reserve from these open databases is a sum of P1 reserves, politically motivated reserves and theCanadian tar sand reserves. Jean Laherrere, former exploration manager for the French oil company,
Total, has for many years collected reserve data and presented them in different articles [3.8], [3.9].
Figure 3.1 shows a time series of these reserves (labelled “political”) against “technical” reserves.
An examination of these “political” reserve numbers would appear to show that reserves are
increasing over time.
Figure 3.1. Global oil reserves in billion barrels (Giga barrels, Gb)reported as Proven (P1) and Proven + Probable (2P) [3.9]

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56 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIESConversely, examination of those reserves labelled “technical” (backdated 2P reserves excluding
extra-heavy oil) provides a completely different picture. Reserves reach a maximum in or around1980, and from that point in time a clear decline in reserves is observable. Future oil production looks
a lot less positive.
The reserve classifications 1P, 2P and 3P were discussed in Section 3.1, and when a new oilfield
is discovered estimates are made according to these classifications. These first estimates are defined in
the discovery year of that oilfield. During the production phase of the field, typically several years
later, more accurate estimates can be made. In a few cases this will reduce the reported size of a field,
but normally we will observe a reserve growth. This reserve growth can be due to field extensions,revision of earlier estimates and the availability of new technologies that improve oil recovery. The
question is when in time this growth should be reported. Industry databases, such as that of IHS [3.10],
locate these changes in field size at the year of discovery. This is known as backdating. In Figure 3.1
the “technical” data points are backdated. This means that all the oil in the field was found the year thefield was discovered, with the consequence that the 2P reserves reached a discernible ceiling aroundthe year 1980 and are now in decline.
Figure 3.2 presents the global annual 2P discoveries of both oil and condensate as reported in
1994 and 2005. The difference in the discoveries for a single year between the two reporting periods isthe backdated growth of existing oilfields. The fields discovered in the 1960s and 70s were found withless advanced methods than the fields found in the last 10 years, and it is no surprise that we get amore substantial growth in the size of fields for this period. Another important detail exposed by thisdata is that we will never again find oilfields as numerous and large as we did in the middle of the lastcentury.
Figure 3.2. Global annual discoveries of both oil and condensate,as reported in 1994 and 2005, together with oil production in billions of barrels (Gb)

The difference in reported reserves between 2004 and 2010 is the reserve growth.
Source: Based on data from IHS Energy, ASPO and Oil & Gas Journal [1.6]

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A separate study of giant oilfield discovery (Figure 3.3) – the fields that today produce more than
50% of the world’s crude oil – generates a clearer picture. Although the number of giant oilfields
found in the 1990s is similar to the number found in the 1940s, those in the 1940s were on averagefour times larger than the fields discovered in the 1990s. It is clear that the 1960s represented thegolden age of the oil industry, and it is unlikely that these golden times will ever return.
Figure 3.3: Discovery of giant oil fields per decade, with respect to number and URR

The most optimistic URR estimates have been used [1.6].

By adding the discoveries given in Figure 3.2 and discoveries from the beginning of the
20 century, we get total cumulative discoveries to date of close to 1 800 Gb. The cumulative
consumption of crude oil has reached 1 000 Gb, and from this we get 800 Gb of reserves, the same
number as in Figure 3.1. Yet in a report dated 2000, the US Geological Survey estimated that by 2025
we should have found 3 345 Gb [3.1]. This number was subsequently used by the IEA for their basecase scenario for future oil production. Following the statistical trends evident in Figure 3.4, it isunlikely that the cumulative discovery rate will have reached the predicted 3 345 Gb by 2025.
th

The discovery trend presented in Figure 3.2 shows a declining rate of discovery and the decade
discovery rate displays a logarithmic decline. Extrapolation of this trend for the next thirty years
provides an expected 150 Gb of discoveries in new oilfields. If we assume that the growth in existing
oilfields will also be in the order of 150 Gb, we obtain a total cumulative value of discovered crude oilby the year 2030 of 2100 Gb. This is far from the number provided by the USGS and used by the IEA
for their scenario analysis.

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58 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES
Figure 3.4: The global cumulative crude oil discoveries [1.1] and the USGS estimate of
crude oil discovery in year 2025

At the ASPO-6 Conference in Cork, 16-17 September 2007, Ray Leonard presented data from the2006 Hedberg Conference [3.12]. This was a gathering of experts from private industry, statecompanies, academia and consultants to discuss world oil reserves and the potential for future growth.
Attendees included representatives of the six largest private companies, major independents, OPEC,
major state companies (Aramco, Petrobras, Petronas, Pemex), state organisations and “think-tanks”.
All attendees were specifically invited and had to make presentations on their areas of expertise. The
press was not allowed access, and presentations were only shared among participants so as to permit
more open discussion.
For seven regions – West Siberia, Niger Delta, SW Africa, North Caspian, Offshore Brazil andSaudi Arabia – estimates by industry experts of growth from exploration were compared withestimates from the USGS. Ray Leonard pointed out that he personally had made the estimate forWest Siberia, for which USGS have reported 55 Gb, but he could perceive only 15% of the figure
provided by the USGS as being realistic. For the seven regions explored, the USGS has a combined
figure of 368 Gb, but experts from within the industry could only see 36% of that as a realistic
calculation. If this holds for the rest of the world, the conclusion is that the IEA must stop using datafrom the USGS in scenarios for future oil production.

3.4 Discovery of heavy oil
The oil resource bases in Alberta, Canada and the Orinoco Belt, Venezuela are usually referred toas unconventional oils. In an historical context, conventional drilling and production methods could
not be used to produce the oil; hence the term “unconventional”. The main reasons for this are thedensity and high viscosity of the oil.

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Heavy oil is not limited to these two areas and heavy oilfields occur all over the world, such as
the Kern River, California, Captain in the UK section of the North Sea, and Duri, Indonesia. However,
the two largest accumulations of heavy oil by far are in the Orinoco Belt and Alberta. Oil from
Orinoco is usually called heavy oil, while the extracted fluid from the oil sands in Alberta is referred
to as bitumen.
Established reserves in the Orinoco Belt equal 37 Gb, but actual oil in place is much larger andthere is therefore the potential for reserve growth in the future. The reserves in Alberta can be divided
into two fractions: a smaller part with 32 Gb that can be mined, and a larger part, 142 Gb, that can beextracted by the “in situ method” [1.7].

3.5 References[3.1]

USGS World Energy Assessment Team, U. S. Geological Survey World Petroleum
Assessment 2000, http://pubs.usgs.gov/dds/dds-060/[3.2]

A detailed description of resources and reserves is given in Section 5, Definitions ofResources and reserves, of the Canadian Oil and Gas Evaluation Handbook;www.ccpg.ca/guidelines/cogeh_section5_definitions_51-101-2667.pdf[3.3]

Mahmoud M. Abdul Baqi and Nansen G. Saleri, Fifty-Year Crude Oil Supply Scenarios:
Saudi Aramco’s Perspective, February 24, 2004, CSIS, Washington D.C.,
http://www.csis.org/media/csis/events/040224_baqiandsaleri.pdf[3.4]

Meling, Leif Magne: How and for how long it is possible to secure a sustainable growth ofoil supply (PowerPoint presentation), 2004-02-27
http://www.bfe.admin.ch/php/modules/publikationen/stream.php?extlang=en&name=en_830
170164.pdf[3.5]

Oil & Gas Journal, http://www.ogj.com/index.cfm[3.6]

BP Statistical Review of World Energy,
http://www.bp.com/productlanding.do?categoryId=6848&contentId=7033471[3.7]

World Oil, http://www.worldoil.com[3.8]

Colin J. Campbell and Jean H. Laherrère (1998), The end of Cheap Oil, Scientific America,
March 1998. On the web: http://dieoff.org/page140.htm[3.9]Jean H. Laherrère, Uncertainty of data and forecasts for fossil fuels, Universidad de CastillaLa Mancha, Ciudad Real, 24 April 2007www.hubbertpeak.com/laherrere/Castilla200704.pdf[3.10]

Homepage for IHS Inc: http://energy.ihs.com/index.htm[3.11]

Reference [3.2], p. 68.

[3.12]

Ray Leonard, World Oil Reserves and Production: Industry View, ASPO-6 2007-09-16.

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4. HISTORICAL CONSUMPTION AND LIMITS FOR FUTURE CONSUMPTION

The BP Statistical Review of World Energy [4.1] is probably the most cited reference when it
comes to a detailed description of oil consumption (it can be accessed via Internet free of charge). This
document includes detailed figures for consumption of crude oil, shale oil, oil sands and NGLs
(natural gas liquids – the liquid content of natural gas where this is recovered separately). For 2005,
the total consumption of these products was reported to be 81.1 million barrels per day (Mbpd).
The IEA has another reporting praxis, which includes as part of the non-conventional fraction
coal to liquids (CTL), etc. They also include “processing gains”, i.e. the increase in the volume of end
products compared with the volume entering the refineries, etc. The IEA reports a global consumptionof 84.5 Mbpd for the year 2005.
4.1 Production forecasts based on the depletion model
In the publication, The Peak and Decline of World Oil and Gas Production, we divide theproduction of oil reported by BP into regular oil, heavy oil, deepwater, polar oil and NGL [1.1].
Figure 4.1 presents an updated version [4.2] of the one detailed in that article.
Figure 4.1. Production of oil and gas liquids to year 2006 [4.2]and production scenarios as described in [1.1]

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Figure 4.1 divides regular oil into the fractions US-48, Europe, Russia, Middle East and Rest ofWorld. Future production of regular oil is considered country by country and then these results are
combined to produce the graph. Separate studies are then made for each of the other fractions andcombined with the data for regular oil. Future regular oil production is based on the fact that thereserves in a country can only be depleted within a certain percentage, the depletion rate.
With just the information for yearly production the change in production for a country can be
expressed in terms of a decline rate, defined as the negative relative change of production over theyear.
(Decline rate) = (Last year’s production – This year’s production)/(Last year’s production).
As oil reserves are not included in the decline rate, it is not suitable for scenarios of future
production.
The depletion rate differs in that it takes into account the amount of oil that is left. It is defined as
this year’s production divided by the amount of oil that is left.
(Depletion rate) = (This year's production)/(Oil left at start of this year).
Clearly, as more oil is produced, less oil is left. At a constant rate of production the depletion rate
grows while the decline rate is zero. The depletion rate can never become negative.
Production for previous years gives the statistical trend for depletion, and new reserves are added
based on previous updates and estimations of oil to be found in the country. The highest depletion
rates are found in the North Sea and the smallest in the Middle East. The strength of this model is that
it is based on the obvious fact that oil has to be found before it can be produced.
The updated forecasts presented in Figure 4.1 are given as updated numbers in Table 4.1 forregular, conventional oil and polar oil. Excluded from this data is production from bitumen, heavy oil,deepwater and Natural Gas Liquids.
Table 4.1. Production of regular conventional oil for 2000 and 2005,
as well as resource-based production forecasts for 2010, 2020 and 2030
Production from bitumen, heavy oil, deepwater and Natural Gas Liquids are excluded
RegionMiddle East Gulf region
Eurasia, including Russia
North America
Latin America
AfricaEuropeAsia-PacificMiddle East minor
Other minor producer
Polar oil, Alaska
World total regular oil
Middle East Gulf Share

2000
MB/d
18.54
11.27
5.29
8.43
6.77
6.53
4.02
2.91
0.47
1.0
65
28%

2005
MB/d
19.77
15.32
4.67
7.97
7.87
5.26
3.67
2.85
0.61
0.8
69
29%

2010
MB/d
19.86
16.07
3.72
5.99
7.33
3.56
3.19
2.28
0.53
0.6
63
31%

2020
MB/d
20.23
11.54
2.11
3.69
5.22
1.71
2.11
1.37
0.38
0.4
49
41%

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2030
MB/d
17.80
7.99
1.21
2.31
3.67
0.83
1.38
0.85
0.28
0.3
37
49%

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4.2 Production from giant oilfields
Section 3.3, “Discovery of crude oil”, discussed giant oilfields, i.e. those fields that will
ultimately produce more then 500 million barrels (Mb) of oil, separately. In the UHDSG-GiantOilfield Database (UHDSG-GOD [1.6]) we have collected all data on the production from giant fields,
and Figure 4.2 illustrates their share of production.
Figure 4.2. World oil production, excluding condensate and NGLs
in million barrels per day (Mbpd),
and the contribution from 312 giant fields and 21 fields with production exceeding 0.1 Mbpd for atleast one year. In addition, the contribution from the largest fields is included [1.6].

The disadvantage with the country-by-country depletion model is that the summing of country
predictions also incorporates the uncertainty of individual forecasts. If the primary interest is toconstruct a global forecast, it is much better to divide the production into the following fractions:-

Giant oilfields;
Small oilfields;
Deepwater oilfields;
New field developments;
Oil sand production;
Heavy oil – Orinoco Belt;
Natural gas liquids.

The open data for giant oilfields gives conflicting values for their URR, and subsequently the best
way to use these numbers is to treat them as upper and lower limits. Table 4.2 presents the data for the
20 largest oil fields in the world.
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Table 4.2. The 20 largest oil fields in the World with respect to URR [1.6]
Field nameCountry

GhawarGreater Burgan
Safaniya
Rumaila
Bolivar Coastal
Samotlor
KirkukBerri
ManifaShaybah
Zakum
Cantarell
Zuluf
AbqaiqEast Baghdad
DaqingRomashkino
Khurais
Ahwaz
Gashsaran

Saudi Arabia
KuwaitSaudi Arabia
N. & S. Iraq
Venezuela
RussiaIraq
Saudi Arabia
Saudi Arabia
Saudi Arabia
Abu Dhabi
MexicoSaudi Arabia
Saudi Arabia
Iraq
China
RussiaSaudi Arabia
Iran
Iran

Discovery year

Production start

1948
1938
1951
1953
1917
1961
1927
1964
1957
1968
1964
1976
1965
1941
1979
1959
1948
1957
1958
1928

1951
1945
1957
1955
1917
1964
1934
1967
1964
1968
1967
1979
1973
1946
1989
1962
1949
1963
1959
1939

Range of URR(Gb)
66-150
32-75
21-55
19-30
14-30
28
15-25
10-25
11-23
7-22
17-21
11-20
11-20
13-19
11-19
13-18
17
13-19
13-15
12-14

An oil company with detailed field information can make sophisticated predictions about future
oil production. In late 2005 the state-owned Mexican oil company, Pemex, made an internal forecast
for the giant oilfield, Cantarell. They presented a “best case” and a “worst case” scenario. Cantarell,
the second largest oilfield in the world when it comes to production, produced 2 Mbpd in December
2005. According to the “best case” scenario, production was predicted to be 1.9 Mbpd over the nextyear, with the “worst case” scenario predicting 1.6 Mbpd. The two different scenarios were based onvarying estimates of URR. The actual production turned out to be 1.5 Mbpd [4.3].
Uppsala Hydrocarbon Depletion Study Group has developed a model to predict future production
from giant oil fields [1.6]. A general model is applied along with a number of outcomes dependent
upon the stated upper and lower limits for the URR (another important parameter is the decline
parameter for giant oilfields). Data from the Cantarell scenarios supports such an approach. Different
future production conditions will be simulated and the range between the various outcomes can serveas an error estimate.
Production from a giant oilfield follows a very specific pattern. Past production includes astart-up period and an early plateau in production based upon installed production facilities. There isthen a late production plateau followed by declining production. Summing the three phases should
yield the applied URR. Analyses of 20 giant fields gives decline rates of between 6 and 16% and threedifferent rates (6, 10 and 16%) are used for different scenarios.
The results of this analysis produced four different possible scenarios. “Worst Case” and “BestCase” as the limits, but the more realistic scenarios are designated the “Standard Case Low End” andOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 – © OECD/ITF, 2008

64 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES“Standard Case High End”. The four scenarios for production from giant oilfields are presented in
Figure 4.3.
Figure 4.3. Future oil production from giant oilfields
million barrels per day, Mbpd [1.6].

The fact that most of the oil in giant oilfields was found between the years 1940 and 1980 (aforty-year period) means that the bulk of their production will go into decline during a rather shorttime frame, and the high decline rates for giant oilfields will mark the beginning of the end of
production.
4.3. Production from small oilfields
The total production from existing oilfields is declining. As an example, Exxon Mobile provides
a range of 4 to 6% in their publication, A Report on Energy Trends, Greenhouse Gas Emissions andAlternative Energy [4.4]. As the giant oilfields tend to have high decline rates we apply only a 3%
decline in the production from existing small oilfields.
4.4. Production from deepwater oilfields
The development of offshore technology for exploration and production of petroleum is a true
landmark in technological development. The first 94 offshore drilling projects took place in waters ofa depth of 11 metres in Summerland, California in 1897 and currently typical water depth is around
1 000 metres.

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Exploration in deepwater (waters exceeding 500m deep) has so far been conducted primarily inthree regions that hold the most discovered resources: the US Gulf of Mexico, Brazil and West Africa.
Figure 4.4 shows the annual deepwater discoveries and further illustrates that exploration really took
off in the mid-1980s, mainly due to advances in seismic reflection imaging, which led to a reduction in
the geological risk involved in deepwater exploration. Data for deepwater oilfields has been collected
in a database [1.6] and this database has been used to determine production forecasts from these deep
water oilfields (see Figure 4.5).
Figure 4.4. Annual deepwater discoveries
billion barrels per year [1.6]

The peak in discoveries at the end of the 1990s is reflected as a peak in production, with
8.8 Mbpd around 2012. Even though new discoveries can make the decrease in production less steep,
we cannot expect this production to offset the decline in production of existing oilfields.

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Figure 4.5. Deepwater production forecast
million barrels per day [1.6]4.5. Production from developments of new oilfields
The future development of oil fields is an essential part of future oil production. Those fields will
help to fill the gap between old declining fields and rising demand. The forecast for future production
from new field developments includes all major developments but excludes deepwater projects(Figure 4.6). Our database covers over 80 fields that came on stream during 2005 or will come on
stream as late as 2013. In addition, some field extensions in non-giant fields that came on stream prior
to 2005 are included (for details, see Appendix B in reference 1.6).
Figure 4.6. Production forecast for new field developments
million barrels per day (Mbpd)

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4.6. Production from oil sand in Canada
The province of Alberta in the south-western part of Canada holds the entire resource base of
Canadian oil sands, and UHDSG has made a “Crash Program Scenario for the Canadian Oil Sand
Industry” [1.5]. Typically, oil sand is assembled in porous rocks and consists of up to 80% sand, silt
and clay. The actual resource extracted from oil sands is bitumen, which in turn goes through further
processing to produce a synthetic crude oil (SCO) suitable for conventional refineries.
There are two main technologies for extracting bitumen from oil sands: open mining and in situ
thermal production. Open mining requires the removal of an overburden in order to reach the oilsands. Some 20% of the reserves, 35.2 Gb, are deposits shallow enough to be mined.

Figure 4.7. Oil production from Canadian oil sandmillion barrels per day from mining and in situ production [1.5]7000

Thousand Bbls Per Day

6000
5000
4000
3000
2000
1000
0
2006 2010 2014 2018 2022 2026 2030 2034 2038 2042 2046 2050
Year

Total Mining, Crash Program

Total In Situ, Crash Program

When the overburden is too thick for strip mining, in situ extraction methods have to be applied,
and the different thermal methods applied have been described in our existing work. One big hurdle in
the expansion of in situ production is the need for natural gas. As an industry rule of thumb, it takes
1 000 cubic feet of natural gas to produce one barrel of bitumen. In addition, some 400 cubic feet ofgas are needed to upgrade one barrel of bitumen to one barrel of SCO [1.5]. Thus, 1 400 cubic feet of
natural gas is required to convert bitumen to one barrel of SCO. The remaining established in situ
reserves are 142.2 Gb. Production for the two scenarios is presented in Figure 4.7, and for the year
2030 we have a maximum production of 5 Mbpd, but this high production needs nuclear power toproduce steam.

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4.7. Production of heavy oil from the Orinoco Belt in Venezuela
The estimated oil in place in the Orinoco heavy oil belt is 1 360 Gb and the latest recovery
estimate approaches 20%, which gives a reserve of 236 Gb. The development of horizontal drilling
techniques and the increased cost effectiveness of both drilling and pumps has made it possible torecover the heavy oil without using costly thermal methods. However, even with these advances intechnology thermal methods are still used to a certain extent.
Figure 4.8. Production from the Orinoco Belt, both historic and a forecast up to 2030
million barrels per day (Mbpd)

Note: Only Hamaca, Cerro Negro, Petrozueta and Sincor are actually in production [1.6].
The production profile for the Orinoco fields is to ramp up to a plateau and then maintain thisproduction plateau for a long period of time. The aim for the four main projects in Orinoco is to keep
the level at 0.6 Mbpd for 35 years. This level is used as the base for the forecast of future Orinoco
production (Figure 4.8). From 2009, a new block will add a production of 0.12 Mbpd and in 2010 afurther new block plus additional production from the first new block will add an extra 0.35 Mbpd.
This leaves a total production, including an assumed orimulsion production, of 0.10 Mbpd and of
1.2 Mbpd in 2012 [1.6].
However, since the resource base is large it is assumed an extra expansion starting in 2015 will
eventually reach 1 Mbpd by 2020. As this expansion continues, total production will reach 2.4 Mbpd
by 2025.

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4.8 Final production profile and conclusions
The aim of the giant oilfield study was to examine the dominant influence on production fromgiant oilfields, so rather than trying to make a detailed analysis of the Natural Gas Liquid fraction, we
have simply assumed that today’s production will remain constant. In Figure 4.9 we have added all thedifferent liquid streams for the Giant High Case scenario.
Figure 4.9. Global liquids production per liquid stream for the Giant High Casemillion barrels per day (Mbpd) [1.6]This scenario allows for an increase in production over successive years at a rate greater than the
1.4% that the IEA use in their demand forecast, but there is no way that we can see a production of
115 Mbpd by 2030. Peak oil for this scenario will occur around the year 2012.
If we now adjust the forecast scenarios to an increase in demand of 1.4%, the peak in oil
production will be delayed and the upper limit for peak oil will be 2018, and this is for the best casescenario (see Figure 4.10).
However, we believe that the high case scenario is unlikely to happen, as it requires the 10 giant
oilfields described in Table 4.3 to come into production shortly. Seven of these fields can be found in
Iraq and investments in these oilfields require political and economic stability in that country.

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Figure 4.10. Global liquids production for all scenarios,with the best case scenario adjusted to fit an annual demand growth of 1.4%,
million barrels per day (Mbpd)

Table 9.3. Major field expansions included in the best case scenario,[thousand barrels per day (kbpd)]
Field production is assumed to increase gradually.
Field

Country

TengizNorthern fields
MajnoonWest Qurnah
HalfayahNahr-Umr
Nasiryah
Zakum Upper
RatawiTuba

Kazakhstan
Kuwait
Iraq
Iraq
Iraq
Iraq
Iraq
Abu Dhabi
Iraq
Iraq

Peak
level
825
900
1000
550
250
500
300
700
200
180

Year ofpeak (kbpd)
2012
2013
2018
2015
2014
2017
2016
2013
2013
2015

Comments

Much delayed projectGradual expansion
Re-development of old field
Re-development of old field
Re-development of old field
Low pressure, poor porosity
Re-development of old field
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4.9

71

Conclusions for production

Production of future oil has been studied with the “depletion model” and with the “giant fieldmodel”. Both models give us a peak in the production of oil in the vicinity of the year 2012. The giant
low-case scenario indicates that we have now just reached a plateau in production that will remain
constant for 5 to 7 years and that we will then witness a steady decline.
Another interesting observation is that both models predict production of between 50-60 Mbpd
for the year 2030. The giant field study can explain this by observing that giant oilfields are alreadydeclining rapidly and that more than 50% of current oil production is in the giant fields. Therefore ourdemand forecast of 101 Mbpd in 2030 (see Section 2.2) cannot be fulfilled.

4.10

References[4.1]

The BP Statistical Review of World Energy, www.bp.com[4.2]

Colin Campbell, ASPO Newsletter 81,
http://www.aspo-ireland.org/contentFiles/newsletterPDFs/newsletter81_200709.pdf[4.3]

David Luhnow, Dying Giant - Mexico Tries to Save A Big, Fading Oil Field, Wall Street
Journal, April 5 (2007), p. A1.

[4.4]

Exxon Mobil, A Report on Energy Trends, Greenhouse Gas Emissions and Alternative
Energy, February 2004.

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5. IMPORT AND EXPORT SCENARIOSOver the years it has been hard to convince politicians, economists, etc., that peak oil is a fact oflife and not just a theory. When it comes to describing peak oil, theoretical methods are used and in
this work we have discussed the “depletion model” and the “giant field model”. A breakthrough inconvincing the individual about peak oil occurs as we begin to discuss the import and export of oil. So
far there has been no other opinion than “the import of oil requires that someone else is willing toexport oil”. The “Peak Oil Moment” arrives and peak oil becomes reality.
5.1 Importing and exporting countries
From the annual figures for oil production/consumption published in the BP Statistical Review ofWorld Energy [5.1], we can determine which countries are net importers and which are net exporters.
In 2005, oil exports were 48 million barrels per day, with 29% of global crude oil exports going to the
US and with Japan and China in second and third place (11% and 7% of global exports, respectively).

Figure 5.1. Net imports of crude oil for the twenty largest importers [1.4]

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Clearly, those nations that require imported oil must find countries that are prepared to export oil,and to date this has been possible, with the exception of the 1970s and 1980s when the flow of oil wasconstricted in the Middle East. Normally the transfer of oil into one country will come from several
different sources. Examining all exports, we find that Saudi Arabia is the number one exporter, with avolume of just over 9 Mbpd, Russia is number two with 6.8 Mbpd and Norway comes third with
2.8 Mbpd. Exports from Norway, a member of the OECD, are now in decline.
During the last thirty years, the annual increase in average Gross Domestic Product (GDP)globally has been 3% per year compared with an average increase in oil consumption of 1.6% per year
[5.2]. In developing countries, the correlation between GDP and oil consumption is stronger than
average. The correlation for China, India and SSA (sub-Sahara Africa) for the time period 1980 to2004 is given in Figure 5.2. The Sub-Sahara Africa region shows no increase in oil consumption percapita and this correlates with a zero increase in GDP per capita for the region [1.7].
Figure 5.2. Development of GDP (PPP) and oil use per capita in China, India and SSA,
1980-2004

In WEO 2006, the IEA forecast that the increase in oil consumption would be 1.4% per year forthe next 25 years, requiring that oil production reach 115 Mbpd by 2030 [2.6]. The US EIA forecasts a
production of 118 Mbpd for the same year [2.7]. Compared with today’s production of 85 Mbpd, anincrease of 30 Mbpd in global production will be required to reach the forecasts of the IEA and theEIA [1.4].
According to the EIA, US consumption will increase by 6.2 Mbpd (30%) by 2030. As production
is projected to stay constant, all of this increase must come from new imports of oil, meaning imports
will increase from 13.8 Mbpd (2005 numbers) to 20.0 Mbpd – an increase of 45%.
China is consuming 7.4 Mbpd and imports reached 3.8 Mbpd in 2006. Over the last five years,
consumption has increased by an average of 9% per year. Production within China is 3.7 Mbpd today
and is expected to decline through to 2030. What future increase in oil demand will we see in China?
A 9% increase would give an unrealistic 54 Mbpd, twice as much as the USA. But a 5% increase will
put China and the USA on the same level, with an import requirement in the order of 20 Mbpd.
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74 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIESThe rest of the importing countries import 31 Mbpd, and a modest increase of 1% per year will
give an additional 10 Mbpd in import demand, producing a combined import requirement in the orderof 80 Mbpd or an increase in the order of 30 Mbpd. Can those countries exporting oil deliver?
Saudi Arabia is the largest oil exporter in the world and no-one denies that this primacy will be
assailed. When there is any discussion of future Saudi oil production, it is normally the business of theoil minister. An exception to this was in February 2004, when Mahmoud M. Abdul Baqi andNansen G. Saleri reported data from the state oil company, Saudi Aramco [5.3]. The production
scenarios presented were labelled Maximum Sustainable Capacity (MSC). Today, the MSC is10 Mbpd and it is proposed this could be maintained until 2042. Another scenario increases production
to 12 Mbpd, maintaining the MSC until 2033. The basis for these scenarios is that the Saudi reserves
are 260 Gb and, as pointed out in 2.2, this is a highly questionable figure.

Figure 5.3. Net export of crude oil for the twenty largest exporters [1.4]

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Figure 5.4. The Saudi Aramco Maximum Sustainable Capacity Production Scenario [7.4]

When trying to determine possible future exports, the growing Saudi population must be taken
into account, as more of Saudi’s oil will be needed for domestic use. Consumption now stands at
2.0 Mbpd, with an average increase over the last 25 years of 5% per year. It will be very hard for
Saudi Arabia to put any restrictions on this domestic consumption, and an increase of 5% per year in
the coming years will increase consumption to 4 Mbpd. The planned production increases reported
will be needed within the country, and therefore we cannot expect ever-increasing exports from
Saudi Arabia.
In early June 2006, the Russian Ministry of Economics announced that Russia would reach amaximum production of 9.85 million b/d in 2009. By accepting this number as a plateau, it is possible
to predict future production from the oilfields in Russia, if URR is known. An alternative method
could be to assume that Russia can increase its production by 2 Mbpd, the same amount that
Saudi Arabia claims to be possible.
There are different opinions about possible future Russian URR grouped around the figures 70,
120 and 170 Gb. Today, BP lists the number 79 Gb. With a modest increase in domestic use anddepletion rates within acceptable values, we have made predictions on future export capacity for
Russia (see Figure 5.5). The 70 Gb scenario appears pessimistic, the 170 Gb over-optimistic, leaving
the 120 Gb scenario as the probable best case. The best case gives exports of between 2 and 3 Mbpd
for 2030 depending upon consumption within Russia [1.9].

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Figure 5.5. Mean export comparison between the reference policy and the alternative policy for
Russia, with respectively 70, 120 and 170 Gb left to produce [1.7]

Norway, the number three exporter today, states that in 2030 its maximum production will be
500 000 b/d, with a possible minimum of 200 000 b/d. Exports for 2005 of 2.8 million b/d will
therefore decline by more than 2 million b/d by 2030.
Mexico is yet another exporter that will lose a big fraction of its export capacity if new fields are
not discovered and massive additional production developed. We know that production from Cantarell
is falling like a rock.
Figure X. Scenarios of total oil use versus projected oil production in SSAOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 – © OECD/ITF, 2008

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The SSA region has been studied in detail [1.7] and it is obvious that an increase in GDP requires
a proportional increase in the consumption of oil. The necessary oil is produced within the region, butOECD countries and China are taking the oil away from where it is needed. Over the next five years,
Angola and Nigeria will increase production by 3 million b/d, but by 2030, production in these twocountries will have declined back to current levels [1.7]. The IEA expects an increase in exports fromthe region by 2030 of 1 Mbpd, but in reality we can expect a decline. If the IEA oil use forecast for theregion is accepted, the decline will be 2 Mbpd.
To avoid any more clouds on this stark horizon, just assuming that other Middle East countries
can keep their export volumes constant – which is a very optimistic assumption – and allowing the
Caspian region an export increase of 2 Mbpd, we conclude that there will be a decline in export
volumes by 2030. Anyone who claims something different must explain in detail what is wrong withthis analysis.
5.2.

References[5.1]

BP Statistical Review of World Energy (www.bp.com).

[5.2]

International Energy Agency, World Energy Outlook 2004;
http://www.iea.org/textbase/nppdf/free/2004/weo2004.pdf[5.3]

Mahmoud M. Abdul Baqi and Nansen G. Saleri, Fifty-Year Crude Oil Supply Scenarios:
Saudi Aramco’s Perspective, February 24, 2004, C, Washington, DC,
http://www.csis.org/media/csis/events/040224_baqiandsaleri.pdf

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6. PRODUCTION OF TRANSPORT LIQUIDS WITH CTL AND GTL

Coal-to-Liquids (CTL) and Gas-to-Liquids (GTL) are fuels that can be produced from coal,natural gas and biomass using the Fischer-Tropsch process. The liquids produced include naphtha,
diesel and a variety of chemical feedstocks. The resulting diesel can be used neat or blended withtoday’s diesel fuel and used in existing diesel engines and infrastructure. In mitigation studies [6.1],
these fuels are discussed as an opportunity to reduce dependence on petroleum-based fuels, but canthey perform this function in reality?

6.1 CTL production
The USA and China are now importing more than 50% of their oil requirements, and this reality
has opened a debate about the use of coal reserves for the production of liquid fuels. The
Fischer-Tropsch method was developed in Germany during the Second World War and used inSouth Africa during the period of apartheid and international sanctions, when they were cut off fromimports of oil. Economically, it has been much more expensive than pumping oil from the ground, andthe fact remains that this technique has only been used to secure liquid fuels when a country is in astate of emergency. The fact that this method is now discussed might indicate that the world isentering just such a state of emergency.
The Coal-to-Liquids Coalition (CTLC) in the USA is using energy security as a motivation for
the further development of CTL production [6.2]: “Establishing a goal of producing at least
300 000 barrels of high-grade fuel per day by 2015 using CTL technology is a feasible target. This isequivalent to the amount of transportation fuel consumed daily by the US military for domestic
operations.”
In China, oil security is also on the agenda and at the ASPO-6 Conference, Professor Pang
(Vice-Chancellor of the China University of Petroleum in Beijing) pointed out that the security goal
for China was to have a self-sufficiency ratio (self-produced-oil/oil-consumption) of more than
50% [6.3]. CTL is part of this equation.

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Figure 6.1. Coal production forecast for China
The peak is even more imminent if the reserves are backdated to 1992
when the last actual updates took place [1.10].

Figure 6.2. Forecasted coal production based on EIA data on the recoverable reserves
and adapted to historical production

The continued rapid expansion of coal production from Wyoming peaks in 2030 and is followed
by a decline, dampened by sub-bituminous coal from Montana. No major increase in bituminous
coal production is possible due to a lack of available reserves. It will also be impossible to reach
the EIA forecast for 2030 [1.10].
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80 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIESThe Uppsala University Hydrocarbon Depletion Study Group has, in collaboration with otherresearchers, made “A resource-driven forecast for future global coal production” [1.10], and we havefound that both China and the USA will face a “Coal Peak” before 2050 (Figures 6.1 and 6.2), andfurthermore there will be increased competition between coal for electricity and CTL production.

Table 6.1. Top five coal producers, 2006 [1.10]
Country
China
USA
India
Australia
RussiaSouth Africa

Production (Mt)
2 380
1 054
447
374
309
240

Share of world
38.4%
17.0%
7.2%
6.0%
4.9%
3.8%

South Africa has a large CTL industry, producing approximately 30% of its fuel needs by
Fischer-Tropsch synthesis. This takes place at the Sasol CTL complex at Secunda, which has a
production capacity of 150 000 barrels per day. As seen in Figure 6.3, this utilizes a significant shareof the country’s coal production, and from Table 6.1 we can conclude that this represents 0.9% of
global coal production.
Figure 6.3. South African coal consumption divided into groups [1.10]

The decline in production from existing oilfields is said to be between 4 and 6%. In absoluteterms, this means that one year from now new production in the order of 4 Mbpd must come on stream
to compensate for the decline. A modern CTL factory might yield 0.2 Mbpd and therefore 20 factories
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could produce the annual decline of 4 Mbpd. With the numbers taken from South Africa, it can beseen that this development of CTL production represents a total requirement of coal that is 60% of
Chinese production, or 60% more than current production within the USA. Compared with global
production, we calculate that 4 Mbpd synthetic diesel needs 25% of the production. New facilities
might be more efficient but even a 50% increase in production efficiency will still draw a substantial
fraction of global coal production.
A massive investment in CTL cannot solve the problem in global oil decline. The 300 000 barrels
per day that the American military needs in the future may be attained.

6.2. GTL production
The gas-to-liquid (GTL) process requires large volumes of low-cost natural gas to compete withdiesel fuel in the open market. GTL produced from pipeline-supplied natural gas would not becompetitive, due to the higher alternative value of pipeline natural gas in the EU and the USA.
Natural gas is more expensive to transport on ships than oil, and converting remote natural gas
into a liquid before transportation is discussed as a more cost-effective method. Since the late 1990s,
major oil companies, including ARCO, BP, Conoco Phillips, Exxon Mobil, Statoil, Sasol, Sasol
Chevron, Shell and Texaco, have announced plans to build GTL plants to produce liquid fuels, buttoday we can see that only a few of these projects may actually reach production. Millions of barrels
will never be produced in the time frame 2008 to 2030.

6.3

References[6.1]

Hirsch, R.L., R. Bezdek, R. Wendling, Peaking of World Oil Production: Impacts,
Mitigation & Risk Management, DOE NETL, February 2005.
http://www.pppl.gov/polImage.cfm?doc_Id=44&size_code=Doc[6.2]

Home page for the Coal-to-Liquids Coalition (CTLC) in USA;
http://www.futurecoalfuels.org/security.asp[6.3]

Pang Xiongqi, Feng Lianyong, Zhao Lin, Tang Xu, Li Junchen, Meng Qingyang,
China University of Petroleum, Beijing, ASPO-6, http://www.aspoireland.org/index.cfm?page=aspo6

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7. POSSIBLE STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIESAt the time of writing, the price of oil has passed $80 per barrel and has remained above thislandmark price for some time. When the Association for the Study of Peak Oil & Gas (ASPO) was
founded in 2001, most authorities on oil held the belief that the future price of oil would not pass $30
per barrel, Table 7.1. When I wrote at that time about peak oil in a number of Swedish newspapers,
my ideas were considered to be crazy, as “Actual forecasts from repayable official and private actors
showed no sign of increase [6.1].” At that time, it was forecast that a price of $80 per barrel in 2010
would be an indicator of peak oil. Today, major players still deny peak oil, even though we have now
seen sustained high oil prices.

Table 7.1. Oil price predictions by agencies and market analysts
at the beginning of 2001, in $ per barrel

International Energy Agency, IEA
US Department of Energy, EIA
European Commission
Canada Department of EnergyStandard & Poor
Deutsche Bank

2010
20
21
20
21
17
18

2020
27
22
24
21
20
18

When it comes to considering import strategies, we must start by examining the USA. Of the20.6 Mbpd the USA consumes, they have a self-sufficiency ratio of 33%. The reality of this is that atleast one supertanker must arrive at a US port every four hours. Any interruption in this pattern is athreat to the American economy. The fact that imports from the Middle East are crucial has inexorably
led to a policy requiring a prolonged military presence in the region. The statement “I am saddened
that it is politically inconvenient to acknowledge what everyone knows: the Iraq war is largely aboutoil”, from the memoirs of the former Federal Reserve Chairman, Alan Greenspan, lends supports tothis position. It should also be noted that President Bush has told the American people that militarybases in Iraq will be needed for the foreseeable future. Furthermore, UHDSG has concluded that evena best-case scenario requires that seven giant oilfields in Iraq must be brought on-stream soon [1.7].
When it comes to Japan and South Korea, we can conclude that their security of supply is
non-existent and they have to rely on an American presence in the Middle East.
Oil production in Europe has passed peak oil, with the United Kingdom passing peak in 1999 and
Norway in 2001. The European decline rate as of 2006 was 7.6%. Europe will become increasingly
dependent upon imports from the Middle East and North Africa (MENA).

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The growing economy of China clearly demands more oil, and with today’s correlation between
growth in GDP and the use of oil we can expect an increase in the order of 10% per year in the coming
years. Since 2000, production within China has increased by 0.4 Mbpd, compared with an increase in
consumption of 2.7 Mbpd. Today, China has a self-sufficiency ratio of 50%. A 10% increase in
consumption equates to 0.7 Mbpd, and with peak oil on the horizon they must obtain this oil byincreasing their imports by the same amount. This is equal to a 20% increase in imported oil.
Figure 7.1. Projected production of oil in China [7.3]

In mitigation strategies for the peak oil problem, China has indicated that it would like tomaintain a self-sufficiency ratio of 50%. To increase quantities of self-produced oil they intend to:a) improve provable ratio; b) enhance oil recovery; and c) develop resources abroad.
Today, the China National Petroleum Corporation (CNPC) operates 65 projects in 25 countries
around the world [7.3], where official policy will be to ring-fence production from these projects for
consumption in China.
On 28 September 2004, the price of oil passed $50 per barrel, and on that day the author
happened to be visiting the giant oilfield Bab in Abu Dhabi. Two days prior to this visit, at theconference on “The Gulf Oil and Gas Sector: Potential and Constraints”, we had discussed calls on the
Middle East made by Guy Caruso and the US EIA earlier that year [7.4]. In a reference scenario, anestimated increase in production was required such that a production of 28.2 Mb/d increased to64.8 Mb/d – a 130% change (see Figure 7.2).

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Figure 7.2: Production capacity year 2001 and demanded production from
US Energy Information Administrationin units of million barrels per day

In the discussion, experienced oil experts stood up one by one and claimed that production should
not be increased: they felt that it was time to think about future generations. The Middle East needed amaximum sustainable level of production; the words from Saudi Aramco were repeated.
When we discussed a potential increase in production from the Bab field, the Field Manager,
Abdulla M. Al-Malood, pointed out that he would prefer to maintain a “sustainable production” levelfrom the region and the fields currently under production. Any increase in production will stress theoilfield and increase the water cut, i.e. the percentage of water produced together with the oil.
Furthermore, he also highlighted the fact that there were new regions that should be coming on stream
as well as some smaller fields tied to the production of the current field. There is the possibility thatseveral other oilfields can be put into production, but surely these fields should be reserved for future
generations.
The fact that Saudi Arabia requires more end-products for domestic consumption means we can
expect that new capacity will be built up in the country. In the future we can anticipate that exporting
countries in the Middle East will change from the export of crude oil to increasing exports of oil
products. As the region cannot grow enough food for the population, other types of employment are
required to generate the necessary income.
We will also probably see Russia compensate for the decline in possible future crude oil exports
by developing exports of oil products with higher revenue potential.
Venezuela is a small oil exporter, but an exporter with a strong political message; exports areneeded for South America. Countries in Sub-Saharan Africa have a similar serious need for oil, but we
do not expect to hear the same message from the exporting countries of West Africa that we hear from
Venezuela.
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A general conclusion is that, with peak oil on the horizon, exporting countries will reconsider theway they export oil in the future. Their actual reserves may be saved for future generations, and thepattern of export products may very well change.

7.1

References[7.1]

Marian Radetzki, Fyndigheter expanderar under resans gang; Brännpunkt, Svenska
Dagbladet, 6 March, 2001

[7.2]

Graham Paterson, Alan Greenspan claims Iraq war was really for oil, The Sunday Times,
September 16, 2007, http://www.timesonline.co.uk/tol/news/world/article2461214.ece[7.3

XiongqiPang, China Syndrome, http://www.aspo-ireland.org/index.cfm/page/aspo6[7.4]

Mahmoud M. Abdul Baqi and Nansen G. Saleri, Fifty-Year Crude Oil Supply Scenarios:
Saudi Aramco’s Perspective, February 24, 2004, CSIS, Washington, DC,
http://www.csis.org/media/csis/events/040224_baqiandsaleri.pdf

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8. AWARENESS OF PEAK OIL

Dr. M. King Hubbert was the first person to become aware of the fact that oil production for a
specific region could peak. In March 1956 he presented the famous paper, “Nuclear Energy and Fossil
Fuels”, for the American Petroleum Institute [8.1]. Hubbert used two different URR numbers for USA(now US-48) in his forecasts: 150 Gb and 200 Gb. Today, we know that the 200 Gb figure is closer tocurrent statistical trends which provide a figure for URR of 220 Gb. The high-case scenario gave apeak in 1973. The most remarkable part of Hubbert’s forecast is that, 44 years before the millennium,
he predicted production to be at 4.1 Mbpd utilising the high case, and in fact actual production turned
out to be 4.2 Mbpd.
The predicted scenarios for US-48 showed that the figure for URR is a crucial number in thecalculation of future oil production. Because discoveries of oil peaked in the 1960s, and the industry
hid this reality by not backdating this data, all estimates of future oil production before 1990 areclearly unreliable. Therefore, statements such as “the forecasts were wrong at the beginning of the20th century and therefore they must be wrong at the beginning of the 21st century” have no scientificvalidity.
The first-ever Oil Depletion Conference took place in Uppsala in 2002 and in its wake theexpression “peak oil” spread around the world. The debate about peak oil in Sweden commenced, andin 2004 the Royal Swedish Academy of Sciences (the organisation handing out the Nobel Prize inPhysics and Chemistry) decided to appoint an energy committee, with its first mission being an
examination of future oil production. In October 2005 a statement was drafted (see Appendix 1) andthis statement, together with activities by ASPO in Sweden, led to the appointment of an Oil
Commission by Swedish Prime Minister, Göran Persson [8.2].
Lines from the Commission report include:“Declining access to conventional oil, in combination with our joint responsibility to stop global
warming, will be a test of the world community’s readiness to switch to energy systems that are moresustainable in the long term. Basically, it is a question of the will to show solidarity with present andfuture generations.
Sweden accepts this challenge.
In this document, we propose a number of far-reaching, concrete measures that can end ourdependence on oil by the year 2020 and tangibly reduce our use of oil products. Our ambitious
objectives are as follows:•••

Through more efficient use of fuel and new fuels, consumption of oil in road transport shall be
reduced by 40-50 per cent.
In principle, no oil shall be used for heating residential and commercial buildings.
Industry shall reduce its consumption of oil by 25-40 per cent.”

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Industry and various agencies have frequently based decisions about future oil production on
predictions by the Cambridge Energy Research Associates (CERA). In June 2006, CERA released aforecast that we criticized in an interview in the Oil & Gas Journal [8.3]. A reply to this critique camein the form of an article, published in the February 2007 issue of Journal of Petroleum Technology(JPT), by Peter M. Jackson from CERA. In the article, Jackson reviewed “Peak Oil Theory” andconcluded that the “… ‘peak oil lobby’ – a group of professionals that forecasts world conventional
oil peaking within a decade – allows fear to replace careful analysis.”
My reply [1.8] concluded: “Figure 1 in the Jackson JPT article shows conventional oil
production for 2006 at around 74 million barrels per day, and is forecast to increase to a maximum of
96 Mbpd in 2030, a plateau production until 2045 and a decline to 68 Mbpd in 2070. Integration
under the CERA forecast plot gives a total conventional oil production of 2 050 million barrels. This isalmost twice as much as we today have as conventional oil reserves, according to CERA. I hope that
CERA now accepts to publish detailed analysis of the prediction, as we are doing.”
It is very encouraging that US Secretary of Energy, Samuel W. Bodman, requested that the
National Petroleum Council (NPC) should undertake a study on the availability of global oil andnatural gas [1.12], and that he specifically mentioned peak oil (see section 1.3). The reply to
Mr Bodman’s request was a huge disappointment. It is unbelievable that the Council “involving morethan 1 000 people actively involved in energy” could not give an answer to Mr Bodman’s question
about peak oil. The 422-page report is simply a description of how to circumnavigate the reality ofpeak oil.
Figure 8.1: Passing peak oil we must land on a “crash mat”

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88 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIESAt the ASPO-6 Conference in Cork, Ireland, on 16-17 September 2007, Dr. James Schlesinger,
the United States’ First Secretary of Energy, was invited as a keynote speaker. For him, peak oil is nolonger a question, simply a stark reality. His statement, “And therefore to the peakists I say, you candeclare victory. You are no longer the beleaguered small minority of voices crying in the wilderness.
You are now mainstream. You must learn to take yes for an answer and be gracious in victory”, was agreat moment. But I am also willing to accept his request that we should be “gracious in victory”. Peakoil must be addressed at all levels in today’s society and we need to work together.
We have climbed high on the “Oil Ladder” and yet we must descend one way or another. It may
be too late for a gentle descent, but there may still be time to build a thick crash mat to cushion the
fall.

8.1

References[8.1]

M. King Hubbert, , Publication No. 95, Shell Development Company, Exploration and
Production Research Division, Houston, Texas, June 1956;
http://www.oilcrisis.org/hubbert/1956/1956.pdf[8.2]

The Swedish Oil Commission, report from June 21, 2006, “Making Sweden an OIL-FREE
Society” (http://www.sweden.gov.se/sb/d/574/a/67096 )[8.3]

Paula Dittrick, CERA study disputes peak-oil capacity growth arguments, Oil & Gas
Journal, Vol. 104, Issue 31, Aug 21, 2006.

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9. ACKNOWLEDGMENTS

This paper was written at the request of the OECD and the International Transport Forum, forpresentation at a Round Table on “Oil Dependence: Is Transport Running Out of Affordable
Fuel?”, held in Paris on 15-16 November 2007. I would like to express my thanks to the organisers forallowing peak oil to be a part of the discussion.
It would not have been possible to present some of the data in this report without the outstanding
work of my students, Mikael Höök, Kristofer Jakobsson, Aram Mäkivierikko, Fredrik Robelius andBengt Söderbergh. Thank you for all of your work.
Finally, I would like to thank Simon Snowden (University of Liverpool Management School,UK) for proofreading the paper and the provision of feedback.

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90 - PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIESANNEX: STATEMENTS 14 OCT 2005

Statements on Oilby the Energy Committee of the Royal Swedish Academy of Sciences
Introduction
The Royal Swedish Academy of Sciences is an independent, non-governmental organisation,with expertise in most of the sciences as well as economical, social and humanistic fields. The
Academy has recently established a committee to consider today’s important energy issues that need
our full, unbiased attention. The Energy Committee has a national as well as a global perspective andwill summarize scientific knowledge on the supply and use of energy as well as the predicted impacts
on society over the coming fifty years. Sustainability and environmental considerations are essential
for any future energy system. Readily available, inexpensive and environment-friendly energy
provides the foundation for economic growth and prosperity.
The Energy Committee has selected a number of subjects to be studied in some depth. One ofthese deals with oil and related carbon-based fuels. Therefore, the Committee organised, together with
the Committee of Energy and Environment of the Royal Academy of Engineering Sciences, a Seminarwith the title, “Running out of Oil – Scientific Perspectives on Fossil Fuels”, held at the Academy on
26 May 2005. Prior to the Seminar, the Energy Committee conducted a hearing with the seminar
participants. More information about this seminar can be found on the Academy’s web page at
www.kva.se. The Committee also arranged a hearing with speakers in an Uppsala Seminar on “Global
oil reserves” on 23 May 2005, together with the Graduate School of Instrumentation andMeasurements (AIM). Members of the Committee participated in the Uppsala Seminar. Someessential points brought up at the hearings and seminars are highlighted below. It should be pointed
out that the perspective given here is not purely scientific, since there are important social, politicaland technical factors that need consideration.
General Remarks
It is very likely that the world is now entering a challenging period for energy supply, due to thelimited resources and production problems now facing conventional (easily accessible) oil. Nearly
40% of the world’s energy is provided by oil, and over 50% of the latter is used in the transport sector.
An increasing demand for oil from emerging economies, such as China and India, is likely to further
accentuate the need for new solutions. In addition, it is important that the poorer countries have accessto oil at reasonable prices to meet their development goals. This places an additional burden on
responsible, mature economies. Compared to many developing countries, the same percentage
increase in the crude oil price will be less problematic for Sweden and other European countries
because of our tax system (crude oil’s share in the gasoline price is quite small – ca. 25% – comparedto taxes). The poor countries will suffer most from an increased price.

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China, India and several nations in South-East Asia and Latin America are now experiencing
rapid economic development. Continued high oil prices will jeopardize their chances of economic
growth. Many countries, for example in Africa, may not even be able to develop economically in theabsence of cheap oil. With China and India emerging as engines of the global economy, the sharp
increase in oil prices which we are witnessing today could lead to a serious international economic
recession, similar to those that followed the oil price increases in 1973-74 and 1981. The European
economies may be severely affected.
There is at present an extreme dependence on supply from the Middle East, which holds morethan 60% of global oil reserves. A key country is Saudi Arabia, which is supposed to hold about 20%of the global reserves of conventional oil and much of the world’s spare capacity. Some analysts
maintain that there are inherent technical problems in the Saudi oilfields, but this is not an uncontested
viewpoint. It is uncertain by how much oil production in the Middle East can be increased in the next
few years and to what extent it would be in the interest of these countries to greatly increase
production. It is clear that, even in these countries, conventional oil is a limited resource on which they
are almost totally dependent. It is, however, also clear that the countries of the Middle East areundergoing massive internal and regional changes, which may have negative consequences for the
global oil supply system. Mitigation measures must be initiated in the next few years in order to securea continued, adequate supply of liquid fuels, especially for the transport sector. Over the longer term,completely new solutions are required. Therefore, increased R&D (Research and Development) in theenergy sector is urgently needed.
Key Points
1.

Shortage of oil

The global demand for oil is presently growing by nearly 2% per year and the current
consumption is 84 million barrels per day (1 barrel=159 litres) or 30 billion barrels per year. Finding
additional supplies to increase the production rate is becoming problematical, since most major
oilfields are well matured. Already 54 of the 65 most important oil-producing countries have declining
production, and the rate of discoveries of new reserves is less than a third of the present rate of
consumption.
2.

Reserves of conventional oil

In the last 10-15 years, two-thirds of the increases in reserves of conventional oil have been basedon increased estimates of recovery from existing fields and only one-third on discovery of new fields.
In this way, a balance has been achieved between growth in reserves and production. This cannot
continue. Fifty per cent of the present oil production comes from giant fields and very few such fields
have been found in recent years. Oil geologists have a wide range of opinions on how muchconventional oil there is yet to be discovered, but new reservoirs are expected to be mainly found in
the deeper water, outer margins of the continental shelves, and in the physically hostile and sensitiveenvironments of the Arctic, where the production costs will be much higher and lead times much
longer than they are today. A conservative estimate of discovered oil reserves and undiscovered
recoverable oil resources is about 1 200 billion barrels, according to the US Geological Survey; thisincludes 300 billion barrels in the world’s as yet unexplored sedimentary basins.

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3.

The Middle East’s key role

Only in the Middle East and possibly the countries of the former Soviet Union is there a potential
to significantly increase production rates to compensate for decreasing rates in other countries.
Saudi Arabia is a key country in this context, providing 9.5 million barrels per day (11% of the current
global production rate). Their proven reserves are 130 billion barrels and their reserve base is said toinclude an additional 130 billion barrels. Iraq also has considerable untapped oil reserves.
4.

Unconventional oil resources

In addition to conventional oil, there are very large hydrocarbon resources, so-called
unconventional oil, including gas (ca. 1 000 billion barrels of oil equivalent, much of which could be
converted to liquid fuels), heavy oil and tar sands (ca. 800 billion barrels) and oil shales(ca. 2 700 billion barrels). Coal, from which liquid fuels can be produced, and methane hydrates
provide a vast additional potential. During a transition period, gas often available adjacent to the oilfields will help to bridge future deficits of conventional oil. With the exception of gas, allunconventional oil is expensive to produce (ca. $20-40/barrel) and exploitation involves significant
environmental problems. At $40 oil, which is now commonly accepted as the long-term equilibrium
price, the cost of developing unconventional oil is less problematic. (see Point 7 below). At present,
1 million barrels of oil per day come from Canadian tar sand and 0.6 million barrels from Venezuelan
heavy oil. The Canadian Government estimates that by 2025 the daily production rate will haveincreased to 3 million barrels per day. Thus, the problem with these unconventional oils is not so muchprice as lead times and non-price-related aspects, such as the effects on the environment andavailability of water and natural gas for the production process.
5.

Immediate action on supplies

Forceful measures to improve the search for and recovery of conventional oil, as well as
improving the production rate of unconventional oil, are required to avoid price spikes, which would
lead to the instability of the world economy in the next few decades. Improved recovery of oil inexisting fields can be expected. The estimated reserves of conventional oil are, however, locatedprimarily in unexplored sedimentary basins, in environments difficult to access, and a substantial parthas yet to be found! Sizeable contributions from unconventional oil need time (some decades) to
become really effective. It is necessary to have public funding for long-term, petroleum-related
research, since this must not be an exclusive task for the oil companies.
6.

Liquid fuels and a new transport system

Oil supply is a severe liquid fuels problem and less of a general energy supply problem; 57% of
the world’s oil is consumed in the transport sector. Unless governments ration oil, there will never be ashortage of oil; just increasing prices. Major programmes therefore need to be implemented to develop
alternatives to oil in the transport sector. Until these measures have been introduced (which may takeone to two decades), demand for oil for the needs of a globally expanding transport sector willcontinue to rise; other users of oil will suffer, including those concerned with power generation.
7.

Economic considerations

At present, the high oil prices are due to the limitations of worldwide production, refining andtransportation capacities. Furthermore, the price is influenced by the threat of terrorist attacks on theworld’s oil supply, transport systems and infrastructure. In the long run, the price of crude oil will be
determined by the price of substitutes. Some estimates indicate that oil may be produced from tar sandOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 – © OECD/ITF, 2008

PEAK OIL AND THE EVOLVING STRATEGIES OF OIL IMPORTING AND EXPORTING COUNTRIES -93

at a price of USD 20-25 a barrel, compared to the present cost of about USD 5 for Saudi Arabian oil.
Liquid fuels from coal could be produced for many decades; cost estimates vary greatly and generally
exceed USD 30. Factors that are hard to estimate are environmental requirements, taxation levels andprofit margins. However, we can anticipate continued high oil prices, as long as the pressure from the
expanding Asian economies is maintained.
8.

Environmental concerns

Unconventional oil will significantly extend the length of the hydrocarbon era, assuming that thenegative impacts on the environment can be avoided. Constraints similar to those imposed on otherfossil fuels (for example, emission controls and CO2 sequestration) will be necessary and provide
major challenges for industry. The impact on the environment in general, and on the atmosphere andclimate in particular, produced by combustion of fossil fuels, is not considered here. However, it isworth noting that such considerations provide further support for the conclusions presented below.
9.

Increased R&D and international efforts

To avoid acute economic, social and environmental problems worldwide, we need a global
approach, with the widest possible international co-operation. Activities in this direction have started
and they should be strongly encouraged and intensified; the technically advanced countries having aparticular responsibility. Considerably increased resources for R&D on alternative non-fossil energy
sources, as well as on the efficient and sustainable use of energy, particularly electricity, are necessary.
In order to develop a sustainable energy system beyond the fossil fuel era, we need a full systemanalysis of the energy sector based on realistic time scales. The Energy Committee intends, in the next
couple of years, to study other sources of energy and evaluate their relative merits and impacts on theenvironment and climate.
Members of the Energy Committee at the Royal Swedish Academy of Science:
Sven Kullander, Professor em., Uppsala University
Gia Destouni, Professor, Stockholm University
Harry Frank, Professor, Mälardalens University
Karl Fredga, Professor em., Uppsala University
Bertil Fredholm, Professor, Karolinska Institutet
David Gee, Professor em., Uppsala University
Karl Grandin, Ph.D., Centre for History of Science
Peter Jagers, Professor, Chalmers Institute of Technology
Bengt Kasemo, Professor, Chalmers Institute of Technology
Rickard Lundin, Professor, Swedish Institute of Space Physics
Karl-Göran Mäler, Professor em., The Beijer International Institute of Ecological Economics
Kerstin Niblaeus, Director General, Council of the European Union
Bengt Nordén, Professor, Chalmers Institute of Technology

The Royal Swedish Academy of Science
Box 50005, SE-104 05 Stockholm, Sweden
Phone: +46 8 673 95 00, Fax: +46 8 15 56 70
E-mail: info@kva.se, Website: www.kva.se

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APPENDIX: RESERVE-DRIVEN FORECASTS FOR OIL, GAS AND COAL -APPENDIXRESERVE-DRIVEN FORECASTS FOR OIL, GAS AND COAL
AND LIMITS OF CARBON DIOXIDE EMISSIONS
Peak Oil, Peak Gas, Peak Coal and Peak CO2

Kjell ALEKLETT
Uppsala University
andInternational Association for the Study of Peak Oil and Gas (ASPO)
UppsalaSwedenOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 – © OECD/ITF, 2008

95

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TABLE OF CONTENTS

ABSTRACT ....................................................................................................................................... 98
1.

INTRODUCTION ....................................................................................................................... 99

2.

EMISSIONS SCENARIOS BY IPPC ....................................................................................... 100

3.

IPCC CLIMATE MODELLING ............................................................................................... 100

4.

FUTURE OIL, GAS AND COAL PRODUCTION AND IPCC EMISSION SCENARIOS ... 102

5.

CONCLUSIONS ....................................................................................................................... 110

6.

REFERENCES .......................................................................................................................... 111

ANNEX ............................................................................................................................................ 113

Uppsala, October 2007

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ABSTRACTThe increase of carbon dioxide (CO2) in the atmosphere is caused by an increasing use of fossil
fuels; natural gas, oil and coal. This is believed to have contributed to an increase in the global
surface temperature of the order of one degree.
In 2000, the Intergovernmental Panel on Climate Change (IPCC), released 40 emission
scenarios, said to be “images of the future, or alternative futures”, and according to IPCC, “they areneither predictions nor forecasts.” These scenarios were based on fossil fuel resources rather thanrecoverable reserves (see preceding chapters).
This analysis is based on realistic reserve assessments. Resources that cannot be transformed
into reserves are not considered. First, we conclude that CO2 emissions from burning reserves-based
oil and gas are lower than predicted by all of the IPCC scenarios, and emissions from coal are much
lower than portrayed in the majority of the scenarios.
IPCC emission scenarios for the period 2020 to 2100 must be altered to more accurately reflect
the fossil fuels that are practically available.
Climate change is current, with more changes to come, and poses an enormous problem forour planet. However, the world’s greatest problem is that too many people must share too little
energy.

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1. INTRODUCTION

The issues of climate change and future increases in temperature have become part of oureveryday life, and central to this debate is the role of carbon dioxide. The fossil fuels we use
contain both carbon and hydrocarbon compounds, and when we burn these products carbon
dioxide is released together with a certain amount of energy.
However, in the climate debate that now rages, it appears that existing quantities of fossil
fuels are not perceived as a problem. The issue is always assumed to be the excessive use ofhydrocarbons and coal. The idea that the combined volumes of these fuels are insufficient toyield the levels of carbon dioxide (CO2) necessary to cause the changes in climate predicted is
not expressed anywhere.
At Mexico’s enormous Cantarell oilfield, production is declining very rapidly. In 2005 theMexican oil company Pemex presented two scenarios for how much oil Cantarell would
ultimately produce; an optimistic estimate with an extraction rate of 50% of the original oil inplace, and a more pessimistic estimate of only 30%. For Pemex and the Mexican Government it
is, of course, a severe blow that reality now appears consistent with the pessimistic scenario;
but this may mean our climate stands to benefit. We have now come to an important decision
point. Shall we regard the oil that remains underground as a resource that can cause futurecarbon dioxide emissions or shall we accept that this finite resource is in fact inaccessible?
Scenarios used by the Intergovernmental Panel on Climate Change (IPCC), are based upon theconsideration that all oil in place is a source for future CO2 emissions. Our analysis uses only
those reserves judged to be technically and economically available now and in the future, andthis makes the predictions “reserve driven”.
The production of oil, gas and coal are limited by today’s reserves, the fraction of theresources that can be produced economically, and reserves that can be found in the future. You
must find oil before you can produce it.
Oil reserves currently displaying declining production have a very limited potential togrow, and the fact that the majority of the productive oilfields are now in decline provides us
with the possibility of estimating the maximum emission of CO2 from oil.
Natural gas fields, on the other hand, have a high recovery factor because gas moves easily
through rock strata. Enhanced recovery is not part of the future of these fields and discovery
trends are the primary driving parameters.
Coal can only be extracted using different kinds of mining. Areas for surface mining areshrinking due to environmental and social considerations. The next generations’ undergroundmines will be very expensive. In Germany, modern mining is more than twice as expensive as
the market price of coal. Reported new reserves are in general smaller than reported earlier,contrasted with growth in existing oil fields.
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If we take the reserves reported in the BP Statistical Review [1] as a potential for future
emissions, we find that gas will produce 400 billions metric tonnes of CO2, oil 600 billion
metric tonnes of CO2, and coal 2 000 billion metric tonnes of CO2. It has been said before, andwe would once again like to point out the fact, that coal is the main problem when considering
future emissions.

2. EMISSIONS SCENARIOS BY IPPCThe IPCC Special Report on Emissions Scenarios [2] describes 40 scenarios for the future andpredicts the extent of greenhouse gas emissions associated with such developments. These scenarios
are based on reviews of the literature, the development of narrative storylines and the quantificationof these storylines with the help of six different integrated models from different countries. The
report illustrates that future emissions, even in the absence of explicit climate policies, depend verymuch on the choices people make: how economies are structured, which energy sources are
preferred and how people use available land resources. Restriction of reserves is not part of thegame.
The scenarios can be seen as images of the future, or alternative futures, but they are notpredictions and they are not forecasts. Different assumptions about the future help create different
images of how the future might unfold. The best way to describe the enormous computer models is
to look at them as some kind of giant “IPCC-SimCity games”[10].
The families in the “game” are called A1, A2, B1 and B2. Every family has a predetermined
future in terms of the growth of population and GDP, land use, available resources and technology
development. Each family creates its footprint in terms of emissions of CO2 from the use of oil, gas
and coal. The emissions are then used in climate models and finally a change of global surface
temperature is calculated.

3. IPCC CLIMATE MODELLING

In the modelling of climate change, the different emission scenarios are the central component,with different curves displaying changes in temperature and labelled according to the different
family names. The most utilised family scenario, showing an unacceptable threat to our planet, is
the A2 family. If this scenario is allowed to develop, the temperature by 2100 will be a whole 3.6
degrees higher than today. The most optimistic scenario is B1, and this least troublesome family
causes a temperature increase of only 1.8 degrees (Figure 1), compared with the reference year
1990[2]. The EU has proposed a target of below 2 degrees.

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APPENDIX: RESERVE-DRIVEN FORECASTS FOR OIL, GAS AND COAL -101

Figure 1. Modulated averages and assessed ranges for surface warming, according to IPCC

The prerequisite for each of these scenarios and the subsequent temperature increase they
represent is that we consume large volumes of oil, gas and coal. The fact that the IPCC calls
upon our politicians to make decisions that will discourage use of fossil fuels creates animpression that the requisite fossil fuel reserves exist on a large enough scale.

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102 - APPENDIX: RESERVE-DRIVEN FORECASTS FOR OIL, GAS AND COAL
Figure 2. The world’s production of all hydrocarbons, excluding tar sand, bitumen, oil shaleand methane hydrate, according to the 2002 scenario [2]World Production of Hydrocarbons

Production [Gboe]

50
40
30
20
10

Non-regular Gas
Regular Gas
Gasplant NGL
Condensate
Polar Oil
Deepwater Oil
Heavy OilRegular Oil

Middle East Gulf
Other
RussiaEuropeUS-48
01930 1940 1950 1960 1970 1980 1990 2000 2010 2020 2030 2040 2050

Year
Regular oil production is divided into production from different regions. US-48 represents the USA
excluding Alaska and Hawaii, and the group “Other” represents the rest of the world.

4. FUTURE OIL, GAS AND COAL PRODUCTION
AND IPCC EMISSION SCENARIOSIn 2003, the Uppsala Hydrocarbon Depletion Study Group (UHDSG) performed a detailed
study on “World Oil Reserves with a Comparison to IPCC Emissions Scenarios” [3]. The different
IPCC emissions scenarios are detailed in this work. Oil and gas production were determinedaccording to the depletion model (DM) described in the paper “The Peak and Decline of World Oiland Gas Production” [4], and the sum of the oil and gas production is illustrated in Figure 2.
The IPCC describes the fraction of different fossil fuels used in the scenarios in terms ofprimary energy per year, and the production figures shown in Figure 2 can be transformed into
energy distributions. Figures 3 and 4 show these distributions in comparison with the IPCC
emission scenarios.
Just take a glance at Figures 3 and 4 and you will realise that the planet cannot provide theamount of energy from hydrocarbons (oil and natural gas) that the IPCC needs to drive thescenarios presented in 2000.

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This can be shown in an even more convincing way by adding each year’s consumption aspresented in Figure 5. The time structure of the distributions given in Figures 3 and 4 can differ, as
well as the total energy consumption given in Figure 5, and if the numbers are too low by a factor of
50% we may just about attain the best-case scenario presented by IPCC.
Figure 3. IPCC’s 40 scenarios on world primary energy produced from oil 1990-2100
compared to the oil production according to the oil depletion model 1930-2100

Note:

The group “all liquids” includes heavy oil, extra heavy oil, deepwater oil, polar oil, gas plant NGL
and condensate.

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104 - APPENDIX: RESERVE-DRIVEN FORECASTS FOR OIL, GAS AND COAL
Figure 4. IPCC’s 40 scenarios on world primary energy produced from gas, 1990-2100,
compared to the gas production according to the oil depletion model 1930-2100

Comparison with IPCC's 40 Scenarios of World
Primary Energy Produced from Gas
1400

1200

Primary energy per year [EJ]

1000

800

600

400

200

0
1940

1960

1980

2000

2020

2040

2060

2080

2100

A1 AIM
A1 ASF
A1 IMAGE
A1 MESSAGE
A1 MINICAM
A1 MARIA
A1C AIMA1C MESSAGE
A1C MINICAM
A1G AIMA1G MESSAGE
A1G MINICAM
A1V1 MINICAM
A1V2 MINICAM
A1T AIMA1T MESSAGE
A1T MARIA
A2 ASF
A2 AIM
A2G IMAGE
A2 MESSAGE
A2 MINICAM
A2-A1 MINICAM
B1 IMAGE
B1 AIM
B1 ASF
B1 MESSAGE
B1 MARIA
B1 MINICAM
B1T MESSAGE
B1HIGH MESSAGE
B1HIGH MINICAM
B2 MESSAGE
B2 AIMB2 ASF
B2 IMAGE
B2 MARIA
B2 MINICAM
B2HIGH MINICAM
B2C MARIA
Regular Gas
All Gas

Year

Note:

The group “all gas” includes non-regular gas, e.g. coal bed methane.

When this data was presented in 2003, the New Scientist wrote an article concerning our
findings [5] (see Appendix 1):“Nebojsa Nakicenovic, an energy economist at the University of Vienna, Austria, who headed
the 80-strong IPCC team that produced the forecasts, says the panel’s work still stands. He
says they factored in a much broader and internationally accepted range of oil and gas
estimates than the “conservative” Swedes.
Even if oil and gas run out, “there’s a huge amount of coal underground that could be
exploited”, he says. Aleklett agrees that burning coal could make the IPCC scenarios cometrue, but points out that such a switch would be disastrous.”
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The same day as this article was released, CNN interviewed the author live and wrote about thearticle on their website [6].
Figure 5. IPCC’s 40 scenarios on world cumulative primary energy produced from oil and gas
compared to cumulative oil and gas production according to the oil depletion model
Comparison with IPCC's 40 Scenarios of World
Cumulative Production of Oil and Gas
120

A1 AIM
A1 ASF
A1 IMAGE
A1 MESSAGE
A1 MINICAM
A1 MARIA
A1C AIMA1C MESSAGE
A1C MINICAM
A1G AIMA1G MESSAGE
A1G MINICAM
A1V1 MINICAM
A1V2 MINICAM
A1T AIMA1T MESSAGE
A1T MARIA
A2 ASF
A2 AIM
A2G IMAGE
A2 MESSAGE
A2 MINICAM
A2-A1 MINICAM
B1 IMAGE
B1 AIM
B1 ASF
B1 MESSAGE
B1 MARIA
B1 MINICAM
B1T MESSAGE
B1HIGH MESSAGE
B1HIGH MINICAM
B2 MESSAGE
B2 AIMB2 ASF
B2 IMAGE

Primary Energy Production [ZJ]

100

80

60

40

20

0
1990 2000 2010 2020 2030 2040 2050 2060 2070 2080 2090 2100
Year

Note:

The group “All Oil and Gas” includes heavy oil, extra heavy oil, deepwater oil, polar oil, gas plant
NGL, condensate and non-regular gas, e.g. coal bed methane.

Most puzzling is that Nebojsa Nakicenovic can reaffirm the panel’s work in light of the results
shown in Figures 3, 4 and 5. At that time, everybody felt that it didn’t matter if you were right orwrong about oil and gas because there was so much coal, and coal emits much more CO2 than oil
and gas. This is correct, and comparatively for 2005 all of the emissions produced by burning gas in
the world only equate to the emissions from burning coal in China. On this basis, UHDSG decided
to do an even more detailed study which included figures from coal.
We have now completed this study, based upon a detailed analysis of future oil and coalproduction, the two major CO2 emitters [9]. By breaking down oil production into seven welldefined parts, we can now give a time-frame for the moment when we will reach the maximum
production rate for oil, “Peak Oil”, the historical peak in production. It will occur between 2008 and2018. If the world’s giant oilfields (those fields that produce 60% of the world’s oil) behave in asimilar manner to Mexico’s Cantarell field, we have the basis for a “worst-case scenario” with a
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production peak in 2008. If instead they follow the best prognosis for Cantarell, and we
simultaneously reduce our consumption, then we get a “best-case scenario” with maximum
production in 2018. When discussing CO2 emissions we should use a “high-case scenario” (Figure6), a picture comparable to the depletion model [2].
Figure 6. The sum of the production from the seven different parts as defined in the figure
with the “Giant High Case” scenario
This is a rather optimistic scenario

We can now, according to our forecast, calculate how much energy/carbon dioxide we can
expect to produce this century if oil is used accordingly, and compare it with the energy
requirements of the IPCC families. To our amazement, we see that families A1, A2, B1 and B2
require more oil than is realistic.
If we extend our analysis and study future natural gas production with what the IPCC families
require, we get an even clearer picture. Natural gas production is declining in North America as is
production in the gigantic Russian gas fields in northwest Siberia, which today account for 90% of
Russian production. Projects planned for the production of diesel fuel from natural gas in Qatar are
being cancelled, and the intended construction of liquefied natural gas reception terminals in the
USA and Europe are being downsized, because global production of liquefied natural gas is now
not expected to reach levels planned for a few years ago. Natural gas is considered by many to be a“transition fuel” to a future, renewable-based society. Today the transition seems to be shorter thanpreviously believed, but in terms of carbon emissions once again we may stand to benefit.

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The third component to be considered when discussing carbon dioxide emissions is coal.
The common belief is that virtually unlimited quantities of coal exist, but when we makedetailed analyses of production profiles in those six nations that have 85% of the world’s coalreserves (see Figure 8), the USA, China, Russia, Australia, India and South Africa, we soon
discover clear signs that coal production in particular regions has reached maximum capacity[7]. Furthermore, we see a decline in production of the best coal, i.e. that which has the highest
energy content. In the USA, the world’s second largest coal user, the volume of coal consumed
is increasing but the actual energy content of the coal used is decreasing. The USA has reacheda coal maximum, “Peak Coal”, in terms of energy content.
Figure 7: Possible world coal production [7]China will soon reach its maximum coal production capacity too and we will then be in asituation where Russia alone sits on the last great coal reserves. That moment in history when
we reach “Peak Coal” is determined by Russia’s future coal production. This forecast is basedon open data, and what we see in our analysis is that every country that makes a new reserve
estimate is down-scaling their reserves. Finally these production profiles are compared with the
IPCC emission scenarios for coal (as for oil and gas, most of the scenarios would not be
fulfilled).
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The total sum of all fossil fuel resources that industry considers accessible is reported every
year in the BP Statistical Review. If we use this optimistic value then the total energy available fromall reserves of oil, natural gas and coal equals 36 ZJ (zettajoules, 1x1021 joules), a massive quantity.
This is more than our research group considers possible but is still less than that reported for all of
the scenario families, A1, A2, B1 and B2. The available energy from fossil fuels is insufficient.
Family A2 is our “worst case” in terms of temperature increase, so let us take a look at its thirstfor energy. In the years to 2100 the IPCC estimates that A2 requires between 70 and 90 ZJ, in otherwords, double the amount that industry believes is accessible. There is then another small detail thatis never discussed, namely that all of the IPCC families require fossil fuel energy subsequent to theyear 2100 (see Figures 3, 4 and 8).
Figure 8: IPCC’s 40 scenarios on world primary energy produced from coal, 1990-2100
compared to coal production according to our data

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APPENDIX: RESERVE-DRIVEN FORECASTS FOR OIL, GAS AND COAL -Figure 9: Cumulative fossil fuel usage for family A2,
70 to 90 Zeta Joule, compared with the total fossil reserves,
according to BP Statistical Review, 36 Zeta Joule.

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Figure 10. Correlations between concentration of carbon dioxide (CO2) in parts per million(ppm) and the ratio between oxygen and nitrogen per meg in the atmosphere [8]5. CONCLUSIONS

It is not necessary here to enter into the debate about fossil fuels as the cause of increased CO2
concentration in the atmosphere. When burning fossil fuels oxygen (O2) in the atmosphere isconsumed and CO2 produced, giving rise to a decline in O2 concentration, a fact illustrated in
Figure 10 [8]. Furthermore, it is known that CO2 is a greenhouse gas and that a higher concentration
will yield an increase in the surface temperature of the planet. The increase of CO2 during the last
100 years may already be more than the climate can take. During the period 2008-2020 we will see
a plateau (or a small decline) in the production of oil, but an increase in gas and coal consumption
will lead to a combined higher emission of CO2 by 2020 than seen today. The conclusions of thispaper do not mean that we should not worry about emissions. The big question is what will happen
after 2020 and for the duration of the 21st century?
The IPCC states that their scenarios can be seen as images of the future (or alternative futures)and that they are neither predictions nor forecasts but different assumptions about the future that canhelp us understand how the future might unfold. The author’s conclusion is that the IPCC emission
scenarios are absolutely unrealistic about the time frame 2020 to 2100 and these “alternative
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APPENDIX: RESERVE-DRIVEN FORECASTS FOR OIL, GAS AND COAL -111

futures” should no longer be given credence. We need a realistic emissions scenario. The Uppsala
Hydrocarbon Depletion Study Group has now combined all of its research for oil, gas and coal andproposes a much more realistic starting point than the time frame 2020 to 2100 [9].
Climate change is current with more changes to come; furthermore, climate change is anenormous problem facing our planet. However, the world’s greatest problem is that too many
people must share too little energy. In the current political debate we presumably need toreplace the word “environment” with “energy”, but thankfully the policies required to tackle
the energy problem will greatly benefit the environment.

6. REFERENCES[1]

BP Statistical Review of World Energy,
http://www.bp.com/productlanding.do?categoryId=6848&contentId=7033471[2]

IPCC, Intergovernmental Panel on Climate Change, Special Report on Emissions Scenarios:
http://sres.ciesin.org/; series; http://sres.ciesin.org/final_data.html[3]

Anders Sivertsson, “Study of World Oil Resources with a Comparison to IPCC Emission
Scenarios”, Diploma Thesis, Uppsala University (2004);
http://www.tsl.uu.se/uhdsg/Publications.html[4]

K. Aleklett and C.J. Campbell; The Peak and Decline of World Oil and Gas Production,
Minerals & Energy, 18 (2003) 5-20 (the article is available at
http://www.tsl.uu.se/uhdsg/Publications/Minerals&Energy_2003.doc[5]Andy Coghlan, Too Little Oil For Global Warming, New Scientist, 5 October 2003:
http://www.newscientist.com/article.ns?id=dn4216[6]

Graham Jones, “World Oil and Gas Running Out”, CNN, Thursday, October 2, 2003
http://edition.CNN.com/2003/World/Europe/10/02/Global.Warming/Index.Html[7]

Mikael Höök, Werner Zittel, Jörg Schindler and Kjell Aleklett, A Resource-Driven Forecast
for Future Global Coal Production, submitted to Energy Policy (2007);
http://www.tsl.uu.se/uhdsg/publications.html[8]Ralph Keeling, The Scripps Institution of Oceanography, USA, Private Communications;rkeeling@ucsd.edu[9]

K. Aleklett, C.J. Campbell, M. Höök, K. Jakobsson, F. Robelius, A. Sievertsson, andB. Söderbergh, to be published.

[10] Simcity Society, http://Simcity.ea.com/

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ACKNOWLEDGMENTS

It would not have been possible to present this paper without the outstanding work of mystudents, Anders Sivertsson and Mikael Höök, who produced the bulk of the work with Peak Oil,
Peak Gas, Peak Coal and CO2 emissions.
I would also like to thank Simon Snowden (University of Liverpool Management School, UK)for proofreading the paper and for the provision of feedback.

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113

ANNEX

“Too little” oil for global warming•••

New Scientist
5 October 2003
Andy Coghlan“Oil and gas will run out too fast for doomsday global warming scenarios to materialise,according to a controversial analysis presented this week at the University of Uppsala in Sweden.
The authors warn that all the fuel will be burnt before there is enough carbon dioxide in theatmosphere to realise predictions of melting ice caps and searing temperatures.
“Defending their predictions, scientists from the Intergovernmental Panel on Climate Change
say they considered a range of estimates of oil and gas reserves, and point out that coal-burning
could easily make up the shortfall. But all agree that burning coal would be even worse for theplanet.
“The IPCC's predictions of global meltdown provided the impetus for the 1997 Kyoto
Protocol, an agreement obliging signatory nations to cut CO2 emissions. The IPCC considered a
range of future scenarios, from profligate burning of fossil fuels to a fast transition towards greener
energy sources.

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“But geologists Anders Sivertsson, Kjell Aleklett and Colin Campbell of Uppsala University
say there is not enough oil and gas left for even the most conservative of the 40 IPCC scenarios tocome to pass (see Figure).
“Billions of barrels“Although estimates of oil and gas reserves vary widely, the researchers are part of a growing
group of experts who believe that oil supplies will peak as soon as 2010, and gas soon after (NewScientist, 2 August 2003).
“Their analysis suggests that oil and gas reserves combined amount to the equivalent of about
3 500 billion barrels of oil considerably less than the 5 000 billion barrels estimated in the most
optimistic model envisaged by the IPCC.
“The worst-case scenario sees 18 000 billion barrels of oil and gas being burnt: five times theamount the researchers believe is left. “That's completely unrealistic”, says Aleklett. “Even the
average forecast of about 8 000 billion barrels is more than twice the Swedish estimate of theworld’s remaining reserves.”“Nebojsa Nakicenovic, an energy economist at the University of Vienna, Austria, who headed
the 80-strong IPCC team which produced the forecasts, says the panel's work still stands. He says
they factored in a much broader and internationally accepted range of oil and gas estimates thanthe “conservative” Swedes.
“Even if oil and gas run out, “there’s a huge amount of coal underground that could be
exploited”, he says. Aleklett agrees that burning coal could make the IPCC scenarios come true,
but points out that such a switch would be disastrous.
“Coal is dirtier than oil or gas and produces more CO2 for each unit of energy, as well as
releasing large amounts of particulates. He says the latest analysis is a “shot across the bows” forpolicymakers.”

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FUTURE PRICES AND AVAILABILITY OF TRANSPORT FUELS -FUTURE PRICES AND AVAILABILITY OF TRANSPORT FUELSDavid L. GREENEOak Ridge National Laboratory
Oak Ridge
Tennessee
USA

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115

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SUMMARY

1. INTRODUCTION ........................................................................................................................... 119
2. GROWING TRANSPORT FUEL DEMAND ................................................................................ 122
3. RESOURCES, OPEC AND THE OIL TRANSITION ................................................................... 124
3.1

Conventional oil resources .................................................................................................... 124

3.2

Unconventional Fossil hydrocarbon resources and coal ....................................................... 130

3.3

OPEC market power and world oil prices............................................................................. 132

4. POLICY & TECHNOLOGICAL CHANGE .................................................................................. 134
4.1

Carbon sequestration ............................................................................................................. 134

4.2

Energy efficiency .................................................................................................................. 135

4.3

Alternative energy sources .................................................................................................... 136

5. THE OUTLOOK FOR TRANSPORTATION ENERGY PRICES ................................................ 137
ANNEX: DEMAND GROWTH, OIL PEAKING AND OPEC MARKET POWER ....................... 141
BIBLIOGRAPHY ............................................................................................................................... 143

Oak Ridge, Revised October 2007

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FUTURE PRICES AND AVAILABILITY OF TRANSPORT FUELS -119

1. INTRODUCTION

It is a truism that future prices of energy for transportation will be determined by the forces ofsupply and demand. For transport fuels, these forces have entered a crucial phase that is likely topersist for several decades. Oil production from conventional resources outside of the OPEC
countries will peak within a few years. Unconventional fossil resources that can be exploited atcurrent prices, resources whose early development is already well underway, pose an even greater
threat to the global climate than conventional fuels. To bring these resources to the market at a rate
to match the growth in demand for mobility fuels in the developed and developing economies will
require massive, risky investments. Serious risks are posed by the environmental acceptability ofthese fuels as well as by the fact that a sudden downturn in world oil prices would turn them into
stranded assets.
It is also a truism that no one can accurately predict the price of oil. Today, oil costs $70 per
barrel. Ten years ago, it cost less than $20 per barrel. Twenty seven years ago oil prices peaked at$90 per barrel (Figure 1). Thirty-seven years ago oil cost only $10 per barrel and its price had been
relatively stable for almost fifty years. Those who carefully craft future oil price scenarios knowthat they are not predicting but rather attempting to define alternative paths of central tendency.
Even the best official oil price projections look nothing like the past thirty-five years of history(Figure 1). It is important to understand why this is so. Since 1972, world oil prices have beenstrongly and unpredictably influenced by the actions of the OPEC cartel. It is very likely that they
will be for the next thirty years, as well.
Figure 1. World Oil Prices: History and Projections
World Crude Oil Prices
$100
$90

2006 $/barrel

$80
$70

Historical
High Price
Reference
Low Price

$60
$50
$40
$30
$20
$10
$0
1925 1935 1945 1955 1965 1975 1985 1995 2005 2015 2025
Source: BP Statistical Review 2007, "Crude oil prices 1861-2006", US EIA, Annual Energy
Outlook 2007, oil price cases.

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120 – FUTURE PRICES AND AVAILABILITY OF TRANSPORT FUELS
Two critical factors have joined the OPEC cartel as the key drivers of future transportation fuelprices:1.
2.

Oil peaking; andClimate change.

Oil peaking is real. It is not a figment of a paranoid imagination. When US crude oil output
peaked in 1970, the United States was the world’s largest producer of crude oil (US petroleum
production including natural gas liquids peaked in 1972). Despite the dramatic price increases
shown in Figure 1, significant new discoveries and profound technological improvements
expanding economically recoverable resources, US petroleum supply never afterwards recovered toits peak level (Figure 2). Many other regions have since gone past their peak (Smith, 2006, counts
60). Peaking of conventional oil production will continue to occur in oil producing regions
throughout the world. It must. It rests on the unexceptionable premise that the rate ofconventional1 petroleum production cannot continue to increase until the last drop is produced.
Figure 2. Peaking of US Petroleum Supply and Imports, 1950-2005

U.S. Petroleum Supply, 1950-2006
25

Net Imports

Million Barrels per Day

Domestic NGLs

20

Domestic Crude Oil

15
10
5
0
1950

1960

1970

1980

1990

2000

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FUTURE PRICES AND AVAILABILITY OF TRANSPORT FUELS -121

The good news is that oil peaking will not mean the end of civilization as we know it. Vastfossil resources exist that can be converted to conventional transportation fuels using proventechnology and at prices below the current world price of oil (IEA, 2006b, pp. 266-271). Indeed,
exploitation of Canada’s unconventional oil sands resources is well underway. Venezuela has vast
reserves of extra-heavy oil in the early stages of exploitation and South Africa has for decades
proven that coal can be converted to excellent gasoline and diesel fuel; and then there is oil shale, of
which the United States possesses vast quantities. Not only can these fuels be produced at prices
the world’s economies have demonstrated they are willing to pay, but they are entirely compatible
with the existing fuel distribution and vehicle infrastructure. Producing conventional liquid fuelsfrom these sources is more capital intensive and more environmentally disruptive than conventional
crude oil production and refining. Even conventional crude oil production has become more capitalintensive as energy companies turn to reservoirs in deeper offshore waters and more hostileenvironments.
The bad news is that all of the unconventional fossil sources, on a well-to-wheel basis, produce
significantly more carbon dioxide emissions than gasoline and distillate fuels refined fromconventional petroleum: from about 20% more for Canadian oil sands to 100% more for gasoline
from coal. As others have pointed out more than a decade ago (e.g. Grubb, 2001), raisingatmospheric carbon concentrations to levels likely to cause dangerous climate change depends on
our continuing to burn coal and on the exploitation of unconventional fossil resources. If most of
the excess CO2 can be captured and sequestered, the transition to unconventional fossil fuels might
conceivably be compatible with climate protection. In any case, coping with the excess carbon
emissions will add to the cost and risk of making conventional transportation fuels fromunconventional fossil resources.
The very large capital investments required to satisfy the world’s growing demand fortransport fuels from conventional and unconventional fossil resources will be subject to increasing
risk. The International Energy Agency (2006, p. 102) estimates that $4.3 trillion (2005 $) will haveto be invested between now and 2030 to meet the world’s growing demands for petroleum. If theworld takes decisive actions to mitigate climate change, either the carbon emissions from theproduction of conventional transport fuels from unconventional fossil resources will have to be
captured and stored, or they will be subject to stiff carbon taxes. Carbon capture and storage will
add significantly to the cost of these fuels, if it is allowed at all. In addition, there will be the risk offalling oil prices. Even with an all-out effort to fill the gap between growing demand and peaking
conventional non-OPEC supply, OPEC is likely to retain its current level of market power in world
oil markets through 2050 at least (Greene, Hopson and Li, 2005). History has shown that OPEC’s
behavior can make prices fall as well as rise, creating even greater risk for energy companies
weighing investments in developing unconventional fossil resources.
All of this adds up not only to higher prices, but to the likelihood of greater volatility. The
world’s oil consumers would be fortunate indeed if future oil prices were only high but stable.
More likely, oil prices will be highly unstable.
The solution to the problems caused by high and volatile oil prices is likely to be policy-driven
technological change. Aggressive pursuit of energy efficiency can extend resources, mitigate
greenhouse gas emissions and enhance energy security. Though it may seem counterintuitive,
sound greenhouse gas policy should also promote the exploitation of existing conventional oil
resources in an environmentally sound way, in order to postpone the transition to more carbon
intensive unconventional fossil resources. And, of course, research and development to further
expand the envelope of energy efficiency, develop appropriate biomass fuels, and eventually
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introduce electricity and possibly even hydrogen as energy carriers for transportation is essential toestablishing a sustainable energy basis for world transport.

2. GROWING TRANSPORT FUEL DEMAND

The current rate at which the world is consuming conventional petroleum is truly alarming.
There is substantial uncertainty about how much conventional oil remains in the world. There isvery little uncertainty about how much has already been used. In 1995 cumulative world oil
consumption amounted to 710 billion barrels (Ahlbrandt et al., 2005, Table 1). Just ten years laterin 2005 cumulative consumption amounted to 979 billion barrels. More than one-fourth of all the
petroleum consumed throughout all of human history was consumed in the last ten years. The US
Secretary of Energy asked the US National Petroleum Council to examine the question of oil
peaking. Their report, entitled “Facing the Hard Truths about Energy”, noted that if present trends
continue the world will consume 1.1 trillion barrels of oil in the next 25 years, more than has been
consumed throughout all history. This would bring total cumulative consumption in 2030 to 2
trillion barrels, two-thirds of the US Geological Survey’s median estimate of the world’s ultimate
resources of conventional oil (Ahlbrandt et al., 2005).
World oil demand is growing chiefly because of the continuing, slow growth in transport
activity in the developed economies and the rapid expansion of motorized transport in developing
economies. The IEA projects that primary oil demand will increase by 1.3% per year, from 84
mb/d in 2005 to 99 mb/d in 2015 and 116 mb/d in 2030. Developing economies are expected toaccount for more than 70% of the increase. The IEA estimates that transportation will account for
63% of the growth of petroleum consumption between now and 2030 (IEA, 2006a, p. 88).
Petroleum demand in the developing world will be driven by the motorization of passenger
transport and the continuing growth of international trade. Taking into consideration the likelihoodthat motor vehicle ownership in developing economies will likely “saturate” at levels well below
those of the US or Canada, still Dargay et al. (2007) project that world motor vehicle ownershipwill increase from about 800 million vehicles today to more than 2 billion in 2030.2 In 2030, wellover half of the world’s vehicles are expected to be in non-OECD countries, compared to about onefourth today. China’s vehicle stock is projected to grow to 390 million vehicles by 2030, twenty
times its size just five years ago. Depending on how successful China is in its efforts to restrain thegrowth of motor vehicle fuel consumption, Huo et al. (2007) project that by 2050 China’s motor
vehicles will consume between 12 and 21 million barrels per day of fuel and emit 2-3 billion metrictons of CO2 each year.
The World Business Council for Sustainable Development (2004) foresees similar growth inboth passenger and freight demand. By 2050 annual passenger kilometres are expected to morethan double from just over 30 trillion in 2000 to over 70 trillion by 2050 (an annual rate of 1.7% peryear). Freight traffic is expected to more than triple over the same period, growing at an averageannual rate of 2.3% per year. The WBCSD study does not expect the modal mix of transport
activity to change dramatically. Highway vehicles are expected to continue to be the predominantmode of transport, despite somewhat faster growth in air and rail freight traffic.

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Worldwide transportation fuel use is projected to double by 2050 despite significant energy
efficiency gains. The Mobility 2030 study projects reductions in energy intensity of 18%, 29% and
29% for light-duty vehicles, heavy-duty trucks, and aircraft, respectively by 2050. The IEA (2006b,
p. 253) asserts that a 40% improvement in the fuel economy of gasoline vehicles could be achieved
at low costs by 2050. Such efficiency gains, though extremely valuable, are not nearly enough tooffset the projected activity increases of 123%, 241% and 400%, respectively, for these vehicle
types. By 2050, global transportation fuel use is projected to reach 5 trillion litres of gasoline
equivalent energy, nearly 180 exajoules, annually.
Figure 3a. World Passenger Travel to 2050 (WBCSD, 2004)

Figure 3b. World Freight Traffic to 2050 (WBCSD, 2004)

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Rising demand increases the potential for volatility in world oil markets, as will be explainedin the following section. The current regime of high oil prices is said to be a demand driven priceshock, to distinguish it from the price shocks of 1973-74, 1979-80 and 1990-91, which clearly
involved a sudden reduction in oil supply. An unanticipated surge in demand, especially from
China and India, clearly contributed to the run-up in prices. Supply constraints also play animportant role in the current high price regime. The continued inability of Iraq, with the world’s
second largest reserves, to increase its oil output certainly helps sustain high prices. Yet the first oil
price shock in 1973-74 was preceded by even more rapid growth in world oil demand. World oil
demand had been growing at the rate of 7% per year when the Arab OPEC oil embargo hit. Equallysignificant is the fact that oil supply from the US, until that point the world’s largest oil producer,
had just gone past peak in 19703. When the entire oil-producing world outside of OPEC passes its
peak, OPEC’s market power will be magnified and the potential for higher and more volatile oil
prices will increase.

3. RESOURCES, OPEC AND THE OIL TRANSITION

The astonishing rate at which the world is consuming petroleum must be placed in the context
of how much oil remains to be produced. How much oil is left? More importantly, can it beproduced at a rate that keeps pace with growing demand? While some believe that oil production
will peak suddenly and soon, and then decline rapidly with disastrous consequences, theconventional wisdom now holds that oil production from non-OPEC regions will soon reach aplateau (or has done so already). Either increased oil supply must then come from OPEC or a largescale transition to unconventional sources of liquid fuels must occur. This implies a magnificationof the market power of the OPEC cartel that is likely to have important implications for the future
costs of transport fuels.

3.1 Conventional oil resources
A comprehensive, scientific survey of world conventional petroleum resources was completed
by the US Geological Survey (USGS) in 2000. USGS geologists estimated the quantities of
conventional oil, gas and natural gas liquids (NGLs) that they judged to be “technically
recoverable” and to have the potential to be added to reserves by 2025 (Ahlbrandt et al., 2005, p. 1).
The estimates include both undiscovered oil and reserve growth for discovered fields. Because
neither can be specified precisely, the USGS estimates are described by probability distributions
rather than single values. Considering only crude oil, the mean estimate of ultimate resources is 3.0
trillion barrels with a 95% probability of at least 2.2 trillion barrels and a 5% probability of morethan 3.9 trillion (Table 1). Ultimate resource estimates also include cumulative consumption todate, as well as proven reserves. Thus, the mean estimate of remaining crude oil in 2005 is 2 994 –979 = 2 015 billion barrels.

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Table 1. USGS Estimates of World Conventional Petroleum Resources through 2025

Undiscovered
Res. Growth
Proved Res.
Cum Prod.
TOTAL

95%
394
255
884
710
2244

50%
683
675
884
710
2953

Oil
5%
1202
1094
884
710
3890

Mean
725
675
884
710
2994

Natural Gas Liquids
95% 50% 5% Mean101
196
387 214
26
55
84
55
75
75
75
75
7
7
7
7
210
334
553 351

95%
495
281
959
717
2454

Total Petroleum
50% 5%
Mean
879
1589 939
730
1178 730
959
959
959
717
717
717
3286 4443 3345

Source: USGS, 2000, as modified to include natural gas plant liquids by Greene et al., 2003.
Units: billions of barrels. Components may not add to totals due to rounding.

How long will the oil last? Unfortunately, dividing the estimated 2 trillion barrels of crude oilremaining by the current annual production rate of 26.5 billion barrels produces not an estimate of
the life of conventional oil resources but yet another measure of their size denominated in unusual
units: years. To be useful to the world’s transportation system oil must be produced at the rate it isneeded, a rate that will continue increasing through 2050. The key insight of peak oil advocates isthat the critical question is not “When will we run out of oil?” but rather “When will we no longer
be able to increase its rate of production?” Disciples of M.K. Hubbert, a Shell geologist who
correctly predicted the peaking of US crude oil production in 1970, believe that oil production
peaks when approximately half of the ultimately recoverable oil in a reservoir has been produced.
Peaking of oil production at roughly the 50% point has been observed in many regions of the world.
When will world conventional oil production peak? On this subject there is considerable
disagreement among experts. The key areas of disagreement are listed below (Greene et al., 2006).
1.
2.
3.
4.

How much conventional oil exists? (see Table 1).
How much oil does OPEC have and how rapidly are they willing to produce it?
How much unconventional oil can be used to replace conventional oil and at what rate?
How rapidly will conventional oil production decline once the peak has been reached?

The Association for the Study of Peak Oil (ASPO) takes the position that the USGS hasgenerally overestimated world oil resources; that OPEC has less oil than it claims to have and that
rates of decline once the oil peak is reached will be consistent with rates of decline observed inregions where oil production has already peaked. Given these assumptions, a peak in global
petroleum production is predicted just after 2010 (Figure 4). Peak oil advocates do not believe that
unconventional resources will be able to fill the growing gap and, as a result, expect drastic demand
destruction as a result of extremely high oil prices.

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Figure 4. ASPO Estimates of Global Oil and Gas Production to 2050

Source: ASPO, 2007.
Gboe = billion barrels of oil equivalent

Government and oil industry forecasts are more optimistic. They assume much larger world
oil resources and expect conventional oil supply to be increasingly augmented by supplies fromunconventional sources such as oil sands, extra-heavy oil, gas-to-liquids and coal-to-liquids. These
forecasts do not see oil shale becoming a significant factor before 2030.
“The concept of peak oil production and its timing are emotive subjects which raise intense
debate. Much rests on the definition of which segment of global oil production is deemed to beat or approaching peak. Certainly our forecast suggests that the non-OPEC, conventional crude
component of global production appears, for now, to have reached an effective plateau, rather
than a peak. Having attained 40 mb/d back in 2003, conventional crude supply has remained
unchanged since and could do so through 2012. While significant increases are expected fromthe FSU, Brazil and sub-Saharan Africa, these are only sufficient to offset declines in crude
supply elsewhere. Put another way, all of the growth in non-OPEC supply over 2007-2012
comes from gas liquids, extra-heavy oil, biofuels (and, by 2012, 145 kb/d of coal-to-liquids
from China).” (IEA, 2007, p. 30)
While they project substantial increases in OPEC output, the increases are in the order of halfof what was predicted before the oil price increases of the past four years. The EIA’s International
Energy Outlook 2006 (IEO2006) Reference Case projects that world oil consumption will increase
from 80 million barrels per day (mb/d) in 2003 to 118 mb/d in 2030, despite an oil price of $57/bbl(2004 $) (EIA, 2006, Ch. 3). OPEC is expected to supply an additional 14.6 mb/d, while nonOPEC countries supply 23.7 mb/d, of which almost half (11.5 mb/d) is from unconventionalsources. This represents a dramatic scaling back of expectations for OPEC production from the
IEO2005. The IEO2005 (which projected only to 2025) expected OPEC supply to increase by 24
mb/d by 2025, while the IEO2006 projects only an 11.8 mb/d expansion for 2025. Consequently,
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higher world oil prices are projected. The IEO2006 low oil price, reference and high oil price cases
project oil prices of $34, $57 and $96/bbl, respectively, in 2030. The corresponding IEO2005
projections were $21, $35 and $48/bbl (for 2025).
Unlike the EIA, the IEA does expect non-OPEC oil supply to peak well before 2030
(Figure 4). However, the IEA foresees not a sharp peak but a plateau.
“Outside OPEC, conventional crude oil production in aggregate is projected to peak by the
middle of the next decade and decline thereafter, though this is partly offset by continued
growth in output of NGLs (i.e. Natural Gas Liquids).” (IEA, 2006a, p. 94).
Figure 5. Non-OPEC Crude Oil and NGLs Production, World Energy Outlook 2006

Source: IEA, 2006a, Figure 3.6, p. 95.
This view is shared by ExxonMobil, whose 2004 projection of world petroleum supply shows
non-OPEC supply peaking in the vicinity of 2015 (Figure 6). Like earlier EIA and IEA projections,
the ExxonMobil projection assumes that OPEC will fill the gap between non-OPEC supply of liquid
fuels and anticipated world demand.

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Figure 6. ExxonMobil Projections of World Petroleum Supply to 2030

Source: Tillerson, 2004.

The EIA’s more recent oil price projections reflect the view that OPEC may fill the gap but
only at much higher oil prices than previously expected. This view is consistent with theobservation that the peaking of non-OPEC supply will magnify the cartel’s market power, and withcareful analysis of production levels that best serve OPEC’s economic interests (Gately, 2004). It isbased on EIA’s judgment that OPEC is less willing to aggressively expand production thanpreviously thought and does not reflect any change in EIA’s assessment of OPEC’s oil resources(EIA, 2006, p. 25). OPEC’s actions are critically important, since lower OPEC output will tend toraise world oil prices and hasten the transition to other energy sources while volatile oil prices will
increase the risk of investing in alternatives to petroleum.
The EIA’s Reference, Low World Oil Price and High World Oil Price cases are defined bydiffering views about: 1) the size of conventional oil resources (ultimately recoverable) and 2) thewillingness of OPEC members to expand production (EIA, 2007, p. 34). The Reference case isbased on the US Geological Survey’s mean estimates of oil and natural gas resources (Ahlbrandt etal., 2005). The High Oil Price case assumes a 15% smaller crude oil resource while the Low OilPrice case assumes that world oil resources are 15% larger. These assumptions affect the degree towhich non-OPEC supply can increase in the three cases. Note that unlike the ExxonMobil and IEA
projections of non-OPEC supply, the EIA’s projections foresee increased non-OPEC supply
throughout the forecast period, but these numbers include unconventional sources such as oil sands,
extra-heavy oil, CTL and biomass-to-liquids (Table 2). In the High Oil Price case, OPEC decreases
output through 2015, then increases it very gradually through 2030. In the Reference case OPEC
output expands from 34 mb/d to 47.6 mb.d by 2030 and in the Low Oil Price case OPEC output
reaches 54.7 mb/d in 2030.

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Table 2. OPEC and non-OPEC oil production in three AEO 2007 oil price cases (mb/d)

OPEC
2005
2010
2015
2020
2025
2030
Non-OPEC
2005
2010
2015
2020
2025
2030

Low Price

ReferenceHigh Price

34.0
34.7
39.3
43.9
49.2
54.7

34.0
34.7
37.5
40.2
43.7
47.7

34.0
31.2
29.1
29.3
31.4
33.3

50.3
57.5
62.1
66.2
70.1
73.4

50.3
56.3
60.2
63.1
66.3
69.7

50.3
55.6
60.9
64.1
66.0
68.3

In terms of a realistic view of future world oil market evolution, these price scenarios have two
problems. First, as Gately (2004) and the EIA itself (EIA, 2006) have demonstrated, the OPEC
cartel can increase its oil revenues by producing less oil. As Figure 7 illustrates, cumulative oil
production of 172 billion barrels through 2025 produces an estimated $7.1 trillion in oil revenues
while producing 63 billion barrels more oil brings in $0.5 trillion less revenue. Countries whose
economy is based on oil revenues will have no difficulty deciding which option is best for them.
Second, all three oil price cases assume the smooth evolution of OPEC output and world oil prices.
As noted above, this is because the projections are intended as descriptions of central tendency
rather than predictions of future price paths. Nonetheless, this is a complete break with the historyof the world oil market since OPEC became a force in it (see Figure 1). In the future, OPEC’s
market power is likely to increase rather than decline. As a consequence, future world oil prices are
virtually certain to be volatile, as explained below.

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Figure 7. OPEC Revenues at Alternative Production Levels, 2003-2025
Cumlative Production and Revenues, 2003-2025:
Middle East OPEC Members
$7.1

$6.7

$6.6

Billions of Barrels

250
200

$8.0
$7.0
$6.0

235.4

$5.0

189.8

150

171.9

$3.0

Production

100

$2.0

Revenues

50

$4.0

$1.0

Trillions of 2003 Dollars

300

$0.0

0
Reference CaseHigh A Oil PriceHigh B Oil Price2005 Annual Energy Outlook Case

Source: DOE/EIA, 2006.
Neither the EIA nor the IEA oil market projections attempt to predict price volatility. Yet thehistory of world oil prices since the first “energy crisis” in 1973-74 shows that volatility has been adominant feature of world oil prices for the past three decades (Figure 5). Until 1973, the UnitedStates was the world’s largest oil producer and its Texas Railroad Commission was reasonably
successful in maintaining stable oil prices. But the peaking of US crude oil production at 9.64 mb/d
in 1970 transferred market power to the OPEC cartel; power it has used inconsistently ever since toinfluence world oil prices. If world conventional oil production outside of OPEC peaks, this too
will add to the cartel’s market influence. While this does not guarantee either higher or morevolatile oil prices in the future, it makes both very likely.

3.2 Unconventional fossil hydrocarbon resources and coal
The path of least resistance will be to fill the growing gap between world petroleum demandand conventional oil supply with conventional fuels derived from unconventional fossil resources.
The quantities of unconventional fossil hydrocarbons from which transportation fuels can be madeare enormous.
Because unconventional petroleum resources have generally been either
technologically or economically impractical in the recent past, there is much greater uncertainty
about their quantities. Unconventional petroleum resources are generally divided into three
categories: oil sands, extra-heavy oils and oil shale. Oil sands and extra-heavy oil have such highviscosities that they will not flow and thus require special extraction methods. Because they lackthe lighter, more volatile components needed in motor fuels, they also require a much greater degreeof upgrading than conventional petroleum. However, both oil sands and extra-heavy oil are
produced today in small (relative to the world’s consumption of crude oil) but increasing quantities,
leading some to consider them conventional resources.

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Unconventional petroleum resources appear to be highly geographically concentrated.
Resources of extra-heavy oil are concentrated in Venezuela, which has roughly 1.2 trillion barrels inplace, with 270 billion barrels recoverable with current technology (IEA, 2006b, p. 265). Oil sands
resources are concentrated in Canada, whose 1.6 trillion barrels (310 recoverable) represents 80% of
the world’s known occurrences. Oil shale occurrences are concentrated in the United States, which
has about 500 billion barrels of medium quality oil shale and about 1 trillion barrels of low quality
oil shale.
The IEA expects production of unconventional oil to increase from about 1.6 mb/d today to
9 mb/d (from 2% to 8% of global supply) by 2030 (IEA, 2006a, p. 97). Most of the increase is
expected to come from Canadian oil sands production (from 1 mb/d in 2005 to 5 mb/d in 2030),
with smaller contributions from gas-to-liquids (2.3 mb/d in 2030) and coal-to-liquids (750 kb/d),
mainly from China. The EIA projects an increase of unconventional oil production from 1.8 mb/din 2003 to 11.5 mb/d in 2030, still just 10% of total liquids production in that year. Production of
unconventional petroleum would increase to 16.3 mb/d in 2030 in EIA’s high world oil price case
(Figure 8).

Figure 8. EIA IEO2006 Projections of World Conventional andUnconventional Petroleum Supply in 2030
EIA IEO2006 Projections of World Conventional andUnconventional Petroluem Supply in 2030
Millions of Barrels per Day

140
120

7.1
11.5

100

21.1

80
60

120.6

40

106.5
80.8
Unconventional

20

Conventional0
Low Oil Price

ReferenceHigh Oil Price

Scenario

Conventional transportation fuels can also be synthesized from coal or natural gas using
established technology and at costs below today’s oil prices ($35-$40/bbl: IEA, 2006b, p. 270). The
cost of converting natural gas to liquid fuels is highly sensitive to the price of natural gas. Given
this, gas-to-liquids projects will likely be limited to “stranded” gas reserves that do not have accessto markets via pipeline and are not large enough to justify an LNG terminal. The IEA estimates that
there are 6 000 exajoules (almost 1 trillion barrels of oil equivalent) of stranded gas in the world,
more than half of which is in the Middle East.

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Conversion of coal into liquid fuels via gasification and catalytic synthesis was firstaccomplished in the early twentieth century. Today, Sasol, a South African oil company, operates
two coal-to-liquid plants with capacities of 150 kb/d that produce 80% synthetic diesel fuel and
20% synthetic naptha. The world’s coal resources are vast and could be an important source ofenergy for the world’s transportation system through the end of the century. However, well-towheel carbon dioxide emissions are more than doubled by coal-to-liquid fuels unless the carbon
produced in the coal-to-liquid conversion is captured and stored. Two-thirds of the carbon in thecoal is released as carbon dioxide in the fuel production process (IEA, 2006b, p. 270).

3.3 OPEC market power and world oil prices
Static or declining conventional oil supplies from non-OPEC oil producers will magnify the
OPEC cartel’s market power with important implications for the level and stability of oil prices andthe costs of transport fuels. Greater OPEC market power is likely to lead not only to higher oil
prices on average but to increased volatility as well. This too is unfortunate because price volatility
increases the risk for energy companies contemplating the large capital investments that will beneeded to satisfy the world’s growing demand for transport fuel.
Greater OPEC market power is likely to increase price volatility because of the order-ofmagnitude difference between the short-run and long-run responsiveness of world oil demand andnon-OPEC oil supply to oil price, and because OPEC is not a single-minded monopolist but a cartel
of sovereign states with differing agendas. Economic theory shows that the market power of amonopolist who controls part but not all of the market increases as: 1) its market share increases, 2)
the price elasticity of demand decreases and, 3) the price elasticity of supply of its competitors
decreases. In addition (as shown in the annex), this market power is magnified when demand is
growing and rest-of-world supply declines. Market power is equivalent to the ability to increase
revenues by decreasing output. The profit-maximizing price of the partial monopolist therefore
depends on its market share, and the price elasticities of demand and rest-of-world supply it faces.
Because these elasticities are ten times smaller in the short-run (~ 1 year) than in the long-run (~ 15years), the price that maximizes OPEC’s profits in the short run is far higher than it can sustain in
the long run4.
Using the static equations for profit-maximizing price presented in the annex to this report,
OPEC’s short-run (upper curve) and long-run (lower curve) profit-maximizing price curves havebeen constructed as a function of its market share (Figure 9). The curves are shown as error bars
rather than lines to reflect the fact that supply and demand elasticities are not known with absolute
precision. On the same graph, historical world oil prices have been plotted against OPEC’s market
share at the time. The pattern is revealing. From 1965 to 1972, as OPEC members were
nationalizing their oil resources and the United States was still the world’s largest oil producer,
prices were below even the long-run profit maximizing level for the cartel. When the Arabmembers of OPEC boycotted the nations that aided Israel in the 1973 October War, world oil prices
shot up above the long-run profit maximizing level (but were still well below the short-run
profit-maximizing level). Prior to that year world oil demand had been increasing by nearly 7% per
year. For the next five years OPEC was able to sustain prices well above the long-run level with
only a modest loss of market share. The loss of oil supply during the Iraq-Iran War caused anotherdoubling of world oil prices, this time to the level of the short-run profit maximizing price curve.
At this point OPEC elected to defend the higher price of oil. However, the cartel’s only weapon is
to further reduce oil production. But cutting back on production means sacrificing market share andloss of market share means loss of market power. Over this period Saudi Arabia sacrificed theOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 - © OECD/ITF, 2008

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most, reducing its oil output from 9.9 mb/d in 1980 all the way to 3.4 mb/d in 1985 (EIA, 2007,
Table 11.5). At that point there was no ammunition left and OPEC was forced to surrender tomarket forces. Prices crashed in 1986. But with three-fourths of the world’s proven oil reserves
and more than half of its ultimately recoverable resources of conventional oil, OPEC’s regaining
market share in a growing world oil market was only a matter of time (Greene, Jones and Leiby,1998). With market share came the rebirth of market power; and when OPEC’s market sharecrossed 40% again in 2004, the price of oil rose sharply.
Figure 9. History of World oil Prices Since 1965 in the Context of OPEC’s
Long- and Short-run Profit-Maximizing Monopoly Price Functions
Cartel Market Share and World Oil Prices: 1965-2006
$100
$90

1979

2006 $/Barrel

$80
$70

2006

$60
$50

1974

1985
1990

$40
$30
$20

2000
1986

1998
1965

$10
$0
25%

30%

35%

40%

45%

50%

55%

OPEC 11 Market Share.
Dependence on petroleum creates enormous economic costs for oil-consuming states. Greene
and Ahmad (2005) estimated the total economic costs of oil dependence to the US economy since1970 at over $4 trillion. Leiby (2007) estimated the external economic costs to the OECD countriesof oil dependence at approximately $40 per barrel. Neither study attempted to count the diplomaticand military costs of conflicts over oil but they are clearly substantial. In his recently publishedmemoir, Alan Greenspan (Paterson, 2007), former chief of the US Federal Reserve Board statedflatly that the ongoing war in Iraq was “…all about oil.” While there is some uncertainty about thesense in which he intended that statement to be interpreted, there can be no doubt that there would
have been no war if there were no oil in Iraq or its surrounding region, or if the world had ample,
economical substitutes for oil. The Iraq war is estimated to have already cost more than half amillion lives (Burnham et al., 2006) and many more injured and displaced. The cost to the Iraqi andUS economies will certainly be numbered in trillions of dollars. Despite the difficulties of
attribution and quantification, the potential for future costly conflicts over oil must not be ignored inany assessment of the future costs of transport fuels.

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4. POLICY AND TECHNOLOGICAL CHANGE

In addition to the forces of supply and demand discussed above, technological change,
especially technological change driven by strong policies to protect the global climate and securesustainable energy sources for global transport, could have the greatest impact not only on the
future prices of transport fuels but on the kinds of energy used to perform the work of moving
people and commodities. Today, alternative energy sources cannot compete with conventional andunconventional sources of liquid hydrocarbon fuels on the scale necessary to do the transportation
work of the global economy. Biomass-derived fuels can make an important but limited
contribution. Energy efficiency improvements based on proven technologies can play a critical roleby limiting the growth of transport energy demand. However, the past thirty years of experience
have shown that technologies that can increase motor vehicle fuel economy will, in the absence ofpolicy constraints, instead be used to provide greater power and weight. New energy carriers likehydrogen or electricity show enormous promise but will need significant technical breakthroughs
and strong policy commitments if they are to displace conventional hydrocarbon fuels. The
potential for a revolutionary transformation in transport energy use is real, however, and just as it
cannot be counted upon it cannot be dismissed.

4.1 Carbon sequestration
The price of carbon will likely be a component of all future liquid hydrocarbon transport fuels.
If carbon prices are in the range of $50-$100 per ton of CO2, transport fuel prices will increase by$0.15-$0.25 per litre. However, if carbon-intensive unconventional fossil resources such as coal-toliquids or oil shale become the marginal source of supply for transport fuels, then the cost of carbon
capture and storage will become an important element of the market price of oil. Fortunately,gasification followed by Fischer-Tropsch synthesis generates a relatively pure stream of CO2
emissions, unlike electricity generation plants. This is an important advantage because capture isbelieved to be the largest component of CCS cost. Capture costs from F-T synthesis are likely to bein the range of $5-$10/tCO2, at the lowest end of the range of capture cost estimates (IPCC, 2005).
Transport adds $1-$8/ton, depending primarily on the distance to a suitable storage site, to which
geologic storage will probably add another $0.50-$8/ton, and monitoring and verification$0.10-$0.30. This would imply very approximately $10-$25/tCO2 , or less than $0.10/litre, even at
the high end of the range. Thus, assuming feasible CCS, the cost of coal-to-liquids transport fuels
may be in the order of $0.25-$0.35/litre higher due to restrictions on carbon emissions.
The feasibility of carbon sequestration is by no means certain. Risks range from gradualleakage from geological formations to catastrophic failures of pipelines. Legal and regulatory
issues remain to be resolved, such as subsurface property rights and liability for CO2 leakage. If
CCS is not feasible for transport fuels, the cost of coal-to-liquid fuels, with double the well-to-wheel
carbon emissions of conventional gasoline, could include an additional $0.30-$0.50/liter in carbon
charges, or $45-$80 per barrel of CTL fuel. The cost differential between CTL and conventional
petroleum would therefore be in the order of $0.05-$0.10/liter ($8-$16 per barrel) with successful
CCS or $40-$55 per barrel without it. If carbon-intensive unconventional fossil resources are themarginal source of supply for transport fuels, prices will be higher by something like $10-$50 per
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barrel, and if there is uncertainty about the costs and feasibility of CCS, they will be potentiallyeven more volatile.

4.2 Energy efficiency
By reducing the rate of growth in demand for transport fuels energy efficiency improvement
can put downward pressure on fuel prices and postpone investments in unconventional resources.
At present, reduction of greenhouse gas emissions rather than petroleum consumption is the primaryobjective driving energy efficiency improvements to motor vehicles. The EU has set a voluntarytarget of 120 gCO2/km for new passenger cars by 2012. In the US, California and other states haveset a mandatory target of 128gCO2/km for 2016. Japan and China have also established comparable
fuel economy standards for light-duty vehicles (An et al., 2007). Relative to current new vehicle
energy efficiencies, these standards represent reductions of from 20% to 33%. This appears to beapproximately the limit of what can be achieved with proven technology and without changing thesize or performance of light-duty vehicles.
The 2006 World Energy Outlook examined two alternatives to its reference scenario designed
to reduce greenhouse gas emissions and petroleum consumption (IEA, 2006a). The Alternative
Policy Scenario (APS) included most policies under serious consideration but not yet implemented.
For example, the US was assumed to adopt California’s greenhouse gas emissions standards forlight-duty vehicles. The EU was assumed to meet its voluntary emissions goals, and the Japaneseand Chinese weight-based standards were assumed to be met and strengthened. All of thesestandards are to be met before 2020, yet additional policies were not considered in the APS.
Modest enhancements of existing biofuels initiatives were also assumed. These policies were
estimated to achieve a reduction in transportation oil consumption of 7.6 mb/d and a reduction intransport’s CO2 emissions of 0.9 Mt, or 11%. A Beyond Alternative Policy Scenario (BAPS)
assumed that the market share of hybrid vehicles would increase to 60% from 18% in the APS, andthat the commercialization of cellulosic conversion technologies would enable a doubling of the
APS biofuels goals. The result was an additional 7 mb/d of oil savings and 1 Gt of CO2 in 2030.
Far more could be achieved with advanced technology almost certain to be production-readybefore 2030 (IEA, 2006b, Tables 5.2 and 5.5). It has been estimated that by 2030, advanced lightduty vehicles with turbo-charged, direct-injection gasoline engines with variable valve timing andlift, variable compression ratios and cylinder cut-out at light loads, combined with improved
aerodynamics, lower rolling resistance tyres, down-weighting via materials substitution andadvanced manual-automatic or continuously variable transmissions, would consume approximately
half as much fuel per kilometre as today’s vehicles (Kasseris and Heywood, 2007). With further
advances in battery technology and electric drive systems, the fuel economy of hybrid electricvehicles could be three times the current level by 2030 (Kromer & Heywood, 2007). Vehicles
would need to be lighter by about 20%, and motorists would have to forego further increases in
power. To have a major impact on transport energy use by 2030, the needed breakthroughs would
have to be accomplished by 2015-2020 to allow time for new technologies to penetrate the global
stock of motor vehicles.
To translate technical energy efficiency improvements described above into reductions inpetroleum use and greenhouse gas emissions, consumers must be willing to forego further increases
in vehicle power and mass. To achieve the 2030 potential for light-duty vehicles, consumers would
have to accept reductions in vehicle mass, but not in vehicle size. Recent US analyses of car size,
weight and safety suggest that overall road safety would be improved if vehicle weights werereduced without reducing track width or wheelbase (Van Auken and Zellner, 2005; Ross, Patel andOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? - ISBN 978-92-821-0121-6 - © OECD/ITF, 2008

136 – FUTURE PRICES AND AVAILABILITY OF TRANSPORT FUELS
Wenzel, 2006) but the issue remains controversial (e.g. Kahane, 2003). A better understanding of
this issue, leading to public acceptance of weight reduction via material substitution, seems essential
to achieve the doubling and tripling of motor vehicle fuel economy envisioned by the engineering
analyses cited above.
Of course, light-duty vehicles are not the only transportation mode that relies on liquidhydrocarbon fuels, although they are certainly the largest consumers. Hybrid technology is well
suited to heavy trucks engaged in local pick-up and delivery operations and could improve energy
efficiency by 25%-45% by 2030 (Duleep, 2007). Similar improvements are possible for long-haultrucks by means of reduced aerodynamic and rolling resistances, reduction of auxiliary loads,
reduced idling, reduced tare weight, and incremental engine and transmission improvements(Duleep, 2007). Recently, Japan has directly challenged the prevailing belief that the market forenergy efficiency in commercial trucks operates efficiently, by establishing the world’s first heavy
truck efficiency standards in 2006 (Wani, 2007). The standards require a 12% improvement inheavy truck and bus fuel economy by 2015. To date, targets for 2006 and 2007 have been met bytruck manufacturers but the jury is still out on the overall efficacy of the standards. If the Japanesestandards prove to be effective, regulating heavy truck fuel economy or greenhouse gas emissions
could become a worldwide policy strategy for curbing oil use and greenhouse gas emissions.

4.3 Alternative energy sources
Global production of biofuels for transport amounted to only about 1% (0.8 EJ) of roadtransport fuel consumption in 2005 (Doornbosch and Steenblik, 2007). Perhaps as much as 20 EJ(11%) of ethanol and biodiesel could be produced by conventional methods by 2050. It is
becoming clear, however, that without breakthroughs in methods of producing biofuels from lignocellulosic feedstocks, such a level of production would have serious impacts on food prices andcause significant environmental degradation. Alternatives to ethanol could be produced via biomass
gasification and Fischer-Tropsch synthesis; however, this pathway faces serious logisticalchallenges with respect to feedstock supply at sufficient scale and regularity to be economical.
Even given technological breakthroughs, the total potential for biofuels may be limited to 40-50 EJ
per year and costs are likely to be in the vicinity of $60/bbl of oil equivalent (IEA, 2006b, p. 283).
Thus, without some form of policy support, biofuels will have difficulty competing withconventional transport fuels from unconventional fossil resources.
Plug-in hybrid vehicles could substitute electricity from the grid for much of the energy
requirements of passenger vehicles, but not without a breakthrough in battery technology permitting
repeated deep discharges and a dramatic reduction in battery cost (IEA, 2006, p. 317). Similarly,hydrogen fuel cell vehicles need perhaps an order-of-magnitude reduction in cost for fuel cellstacks, as well as a breakthrough in on-board hydrogen storage. Looking forward, the task ofdisplacing significant amounts of conventional fuels with hydrogen and electricity seems daunting.
Looking backward at the past twenty years of progress in battery and fuel cell technology, on theother hand, it seems quite possible.
Technological change is certain. Whether it will go far enough and fast enough to change theenergy basis of transport remains to be seen. In any event, without strong public policies neither
major fuel economy improvements nor significant market shares for alternative energy sources
seem likely.

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5. THE OUTLOOK FOR TRANSPORTATION ENERGY PRICES

Reference case forecasts of future oil prices foresee a period of declining or slightly rising
prices through 2015, followed by gradually increasing prices through 2030 (Table 3). As measuresof central tendency, these projections appear to reflect the likelihood that unconventional fossil
resources will become the marginal sources of supply for transportation fuels, since it appears thateven CTL can be produced at costs in the vicinity of $40-$50 per barrel (IEA, 2006b, p. 270).
The forecasts also may reflect the marginal cost of CTL-derived fuel in the presence of strong
carbon constraints, if CCS is feasible. Given a carbon price in the order of $50/tCO2, if CCS is
feasible and the IPCC cost estimates are approximately correct, CCS would add about $10-$25 perbarrel to the cost of CTL liquids. CTL liquids, however, are superior in quality to crude oil-derived
fuels and might command a premium in the order of $10 per barrel. The IEA and EIA reference oil
price projections of $55-$59 per barrel are roughly consistent with such a scenario. However, if
CCS is not feasible and CTL is the marginal source of supply, the additional fees for double thecarbon emissions might imply that these estimates are $10 per barrel, or so, on the low side. In theworld of 25-year oil price projections a difference of $10 per barrel is in the noise.
Table 3. Projections of world oil prices, 2010-2030
Projection
IEA Reference
AEO Reference
AEO Low World Oil Price
AEO High World Oil Price
Global Insights, Inc.
Energy & Environmental Analysis, Inc.
Deutsche Bank AG
Strategic Energy & Econ. Res., Inc.
Energy Ventures Analysis, Inc.

2010
$52
$57
$49
$69
$57
$57
$40
$44
$42

2015
$48
$50
$34
$80
$47
$50
$40
$45
$42

2020
$50
$52
$34
$89
$45
$47
$40
$46
$46

2025
$53
$56
$35
$94
$43
$45
$40
$46
$49

2030
$55
$59
$36
$100
$40
NA
$40
$47
NA

Source: EIA Annual Energy Outlook 2007, Table 19 (rounded to nearest dollar).

What is virtually certain is that future oil prices will not follow the smooth paths that thesemeasures of central tendency may seem to imply. OPEC’s increasing market power will makefuture price volatility more likely. In addition, the risks that energy companies face with respect tothe massive investments they must make to increase liquid fuel supplies to meet growing world
demand, imply that the expansion of supply is not likely to be smooth and orderly.
It seems far more likely that future oil prices will evolve in patterns similar to those illustrated
in Figures 10a-10c. The “shocked” cases shown in these three figures simulate the impacts on
world oil prices of deviations from the projected OPEC oil supply. The OPEC supply deviations
have been calibrated to be similar to actual differences from historical projections by the US Energy
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138 – FUTURE PRICES AND AVAILABILITY OF TRANSPORT FUELS
Information Administration (Greene and Leiby, 2006). The three price cases shown in the threegraphs reflect EIA’s judgment about how differences in the quantity of conventional oil resourcesthat actually exist and OPEC’s willingness to expand production will affect the general trend of oil
prices in the future. The graphs below are but a few of an infinite number of possible future pricepaths. In that sense, the probability that any one of them will be the true future price path is zero.
They are shown simply to illustrate the strong likelihood that future transportation fuel prices will
be volatile rather than regular, and that while prices may be higher than in the past, they may also attimes be much lower than they are today.
Figure 10a

World Oil Price: History Through 2005,
AEO Reference Case & Supply Shock Simulation$100
2003 $/BBL

ShockedReference case

$80
$60
$40
$20
$0
1970

1980

1990

2000

2010

2020

2030

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FUTURE PRICES AND AVAILABILITY OF TRANSPORT FUELS -Figure 10b

World Oil Price: History Through 2005,
AEO High Case & Supply Shock Simulation$100
ShockedHigh Oil Price Case

2003 $/BBL

$80
$60
$40
$20
$0
1970

1980

1990

2000

2010

2020

2030

Figure 10c

World Oil Price: History Through 2005,
AEO Low Case & Supply Shock Simulation$100

2003 $/BBL

ShockedLow Oil Price Case

$80
$60
$40
$20
$0
1970

1980

1990

2000

2010

2020

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2030

139

140 – FUTURE PRICES AND AVAILABILITY OF TRANSPORT FUELS

NOTES

1.

Conventional petroleum is defined as liquid hydrocarbons of light and medium gravity andviscosity in porous and permeable reservoirs. Unconventional oil consists of deposits with adensity greater than water or with high viscosity (> 10,000 cP) or found in tight formations.
Conventional petroleum will flow in underground reservoirs and can therefore be producedwith conventional drilling methods. It also has a relatively high hydrogen-to-carbon ratio andso requires relatively little addition of hydrogen to be converted to transportation fuels such as
gasoline and distillate. About two-thirds to one-half of the petroleum in a reservoir (depending
on reservoir conditions and production methods) remain in the ground when production fromthat reservoir ceases. Conventional petroleum recoverable by enhanced recovery methods andliquid hydrocarbon by-products of natural gas production are often included in the definition of
conventional petroleum. Some now consider Canadian oil sands to be conventional resources
but in this report they are classified as unconventional.

2.

Saturate is a poor choice of words. Auto ownership continues to increase even in auto
“saturated” economies such as the United States. More accurately, the growth in ownershipwill slow substantially.

3.

While US crude oil production peaked in 1970, US total petroleum production including
natural gas plant liquids actually peaked in 1972, the year before the first oil price shock.

4.

Moreover, long-run price elasticity will be affected by technological change and is therefore
always uncertain.

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ANNEX:
DEMAND GROWTH, OIL PEAKING AND OPEC MARKET POWER

Growing demand for oil or shrinking supply capability from competitive oil producers magnifies
the market power of the partial monopolist. Assume that oil demand is growing exogenously at a
rate of r×100% per year and, in addition, that rest-of-world supply is exogenously shrinking at
δ×100% per year. Shrinking supply may be a more controversial assumption than growing demand
which has been observed throughout the world as economies expand. Shrinking supply might occur
as a result of the peaking of conventional oil production, if alternative unconventional sources ofliquid fuels cannot be brought on line quickly enough. In any case, the derivation presented below
is equally valid for the special case where δ=0.
Once again, the partially monopolistic cartel is assumed to maximize its profit, Π, which is afunction of the market price, P(q, Qo), which depends on the supply from the cartel, Qo , as well as
the supply from the competitive producers, q. For convenience, it is assumed that the marginal costof production for the cartel is constant at C. With exogenously growing demand and shrinking
supply the cartel’s profit function is the following.

(

)

(

)

Π (Qo ) = P qe −δt + Qo Qo − CQo = P Qe rt Qo − CQo
The first order condition for maximizing profit is obtained by differentiating with respect to Qo .

⎤∂Π ∂P ∂Q
∂P ⎡ −δt ∂q
Qo + P − C = e rt=
+ 1⎥Qo + P − C = 0⎢e∂Qo ∂Q ∂Qo
∂Q ⎣
∂Qo
⎦
Dividing through by P, multiplying the first term on the right-hand side by Q/Q and rearranging
terms gives the partial monopolist’s profit maximizing pricing rule in a dynamic market.

e rt⎤∂P Q Qo ⎡ −δt ∂qC+ 1⎥ + 1 =⎢e∂Q P Q ⎣
∂Qo
P
⎦

P=

C
⎤
1 ⎡
∂q
1 + e rt σ ⎢e −δt
+ 1⎥
β ⎣
∂Qo
⎦

From the profit maximizing price equation it is clear that a growing market demand effectively
multiplies the market share of the cartel. A shrinking ROW supply also magnifies the market powerof the cartel, since ∂q/∂Qo < 0 and thus 0 < e-δt < 1 will cause the term in square brackets to increase.

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142 – FUTURE PRICES AND AVAILABILITY OF TRANSPORT FUELS
A growing market demand or a shrinking ROW supply has another, possibly more important
implication. Whereas in a static market the only way for the monopolist to cause price to rise is to
cut production, in a growing market all that is needed for price to increase is to not expand
production. This could be a critically important determinant of the cartel’s ability to achieve
cooperation among its members. Undoubtedly it is easier to persuade members not to expand
output than to agree to and carry out production cuts.

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MEDIUM-TERM OIL MARKET UNCERTAINTIES -MEDIUM-TERM OIL MARKET UNCERTAINTIES

Lawrence EAGLESHead, Oil Industry & Markets Division
IEA
Paris
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147

MEDIUM-TERM OIL MARKET UNCERTAINTIES -149

SUMMARY

1. OVERVIEW ................................................................................................................................. 151
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8

Demand methodology .......................................................................................................... 151
Forecasting uncertainties...................................................................................................... 152
Prices ................................................................................................................................. 152
Substitution .......................................................................................................................... 154
Subsidies .............................................................................................................................. 155
Economic growth ................................................................................................................. 155
Data ................................................................................................................................. 156
Biofuels ................................................................................................................................ 157

2. SUPPLY-SIDE UNCERTAINTIES................................................................................................ 158
2.1
2.2

Project slippage .................................................................................................................... 159
Decline rates......................................................................................................................... 159

3. INVESTMENT................................................................................................................................ 161
3.1
3.2
3.3

Prices ................................................................................................................................. 161
Operating environment and constraints ............................................................................... 161
OPEC supply ........................................................................................................................ 163

4. CONCLUSION ............................................................................................................................... 163

Paris, revised January 2008

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1. OVERVIEW

The oil market has changed dramatically over the past eight years, with prices rising from $10
to over $90/barrel. The dynamics of the industry have changed, but there is still considerable debate
over whether this represents a paradigmatic shift of supply and demand conditions or is simply aresult of longer term cyclical factors. Non-OECD oil demand growth is running three times fasterthan in the OECD, and is set to surpass the OECD in volumetric terms in the middle of the next
decade. Non-OPEC supplies have plateaued over the past five years and look set to remain at suchlevels for the coming five years. Understanding the drivers behind these shifts gives an insight into
the prospects for the coming years. However, even looking five years forward, there are many
variables which could affect the outcome. These forecasts therefore provide a guide to the future,but should not be expected to project supply and demand with pinpoint accuracy. Equally importantis the need to understand the uncertainties which lie behind any forecast that could change the final
outcome.
This paper derives from the extensive work undertaken by the International Energy Agency for
its Medium-Term Oil Market Report, and looks at the variables and forecasting uncertainties that
could alter the forecast path.
1.1 Demand methodology
Our econometric demand model is primarily driven by the GDP assumptions provided by the
IMF’s World Economic Outlook, combined with a price assumption of IEA import prices (derived
from the prevailing ICE1 Brent futures curve). Using historical data, this model is adjusted toaccount for short-term factors (unseasonable weather variations, retail tax changes, etc.) and longerterm structural shifts (such as interfuel substitution, changes in the vehicle fleet or petrochemical
expansions, and policy changes, etc.), in order to determine an underlying demand trend by productand country.
This “top-down” approach implies calculating income and price elasticities for every major
product group for all countries in the world. This allows us to assess the global trends for eachindividual product market – which can often be very different from an assessment based on total oil
demand. For example, transportation fuels tend to be more income-sensitive, while fuel oil, which ismore readily substitutable, is more price sensitive.
Our demand analysis is complemented by “bottom-up” sectoral analysis, which focus onchanges in end-user demand – for example, the impact of the switch from gasoline to diesel vehicles
in Europe, the effects of the rapid expansion of petrochemical capacity in Asia and the Middle East,or the growing use of natural gas and coal for power generation in Europe. Although this approachprovides a valuable comparison with the main “top-down” assessment, its results must be
interpreted with caution. For example, will there be sufficient feedstock supply (predominantly
naphtha) to sustain China’s petrochemical expansion plans? Will this expansion result in a regional
petrochemical surplus, leading to the closure of less efficient plants?

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1.2 Forecasting uncertainties
Global demand is predominantly driven by two primary forces, price and income. If theassumptions underlying those variables are wrong, then the output of the model will be affected.
Similarly, the robustness of the historical data underpinning the model is important. Finally,
substitution issues can work in many ways, leading to additional modelling complications.
1.3 Prices
When constructing our medium-term forecasting model, a price assumption was one of theharder concepts to incorporate. The dynamics of the oil market have changed considerably over the
past five years and we are unaware of any formal price model that predicted a rise in the oil pricefrom $25 to $90/bbl over the past four years. The seemingly robust relationship between oil stocks
in the OECD and prices appeared to break down. Additional inputs, such as refining capacity, spare
upstream capacity, investment flows, natural gas prices and the term structure changes between spot
and forward prices, have all had an impact.
Ultimately, the decision was taken to use a price assumption derived from average IEA importprices and the futures curve. This provided the opportunity to look at future developments undercurrent market assumptions. By definition, this also means that the rest of the model is assessed
under the same conditions – i.e. it is a static model designed to highlight where current market
forecasts potentially lead to imbalances. These imbalances, in our opinion, offer the greatest insight
into the medium-term market direction. The medium-term forecasts are therefore not the outcomeof a dynamic equilibrium model of oil supply and demand.
There is a lively academic debate over the usefulness of the futures curve in predicting market
prices. Although a market-derived price allows consumers and producers to fix prices up to sevenyears in the future (by effectively purchasing the right to buy or sell oil in the future at a price fixed
today), the only portion of the futures curve that has a strong predictive record is the refining
margin derived from NYMEX crude, gasoline and heating oil futures curves, as evidenced byempirical studies. Under tight market conditions, the spot oil price tends to trade above forward
months to form a “backwardated” price structure. The steepness of the curve tends to reflect therelative scarcity of spot material, and the formation is therefore generally associated with rising
prices. As such, while cyclically prices may be expected to fall once a bull market has finished, abackwardated market curve shows limited explanatory insight during the rising price trend.

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$/bbl

153

NYMEX WTI
Forward Curve

100
90
80
70
60
50

Source: Platts

40
M1

M6

M11

M16

M21

18-Jan-07
21-Nov-07$/bbl

NYMEX WTI
Front Month Spreads

2.0
1.0

M26

20-Sep-07
18-Jan-08

Backw ardation

0.0
-1.0
-2.0
-3.0

Contango

Source: Plat ts-4.0
Jan 07

Apr 07

Jul 07

Oct 07

Jan 08WT I M 1- M 2

The opposite situation is a “contango” structure, generally seen when the oil market is amply
supplied and the spot price is below forward prices. Market theory shows that there should be an
upper limit to the forward price rise representing the cost of storage, finance and insurance at the
point of pricing. Typically, a contango structure is associated with falling prices, which again is oflimited value except at the bottom of a bear market, where prices are expected to rise. However,
over the course of the past four years, the average rise in oil prices has been over $12 per year, withintra-year volatility sometimes being over $20/barrel both up and down. Atypically, this rise in
prices has also been associated with a contango structure for the past two years.

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However, while the traditional relationship of a contango market and falling prices has been
turned on its head, there remains a strong link between the spot and forward price differential andstock levels. Unusually, crude prices have been rising, despite rising stockpiles. This has led toconsiderable debate between analysts: has the rising crude price been a reflection of anticipatedlonger-term oil market tightness and the need for more investment and energy conservation? Is it acomplex interaction, reflecting the mismatch between the structure of crude product demand andspare refining capacity, or merely a distortion relating to the large inflows of passive investment
money into commodities?
Ultimately, by using a futures curve, the MTOMR produces a forecast that displays potential
imbalances in the future that could necessitate further price shifts to achieve the necessary
equilibrium outcome, rather than trying to adjust the price to induce market balancing shifts insupply or demand. Arguably, as the market has shown over the past few years, stock shifts, which
are of little relevance in long-term projections, can considerably influence medium-term outcomes.
1.4 Substitution
Interfuel substitution is in essence a further price effect, but one much harder to model. The
most obvious fuel shift both to and away from oil involves the usage of natural gas in the power
generation sector. Unfortunately, there is no global natural gas price through which these effects canbe easily modelled. As planning and construction of gas-fired power generation takes years, thestructural shift away from oil is derived from an expected long term running cost advantage fornatural gas. However, as long as there is fuel switching capacity or idled capacity that can quickly
be brought back into service, there can be shorter-term substitutions.
While the expansion of LNG trade may lead to a convergence of prices around the world, alarge number of natural gas supply contracts (in Europe and Asia) are related to oil prices. This canlead to shifts in power generation demand for natural gas that are unrelated to economic trends ingas supply and demand. Where natural gas prices are derived from a long-term moving average ofoil prices, volatility in the oil price can lead to periods where there are significant differences
between oil and natural gas prices. Ultimately, in these instances, US natural gas futures prices canbe used as a barometer for fuel switching potential. Nevertheless, increased fuel oil demand is either
related to natural gas generating capacity constraints, supply issues, or weather-related demand
surges, rather than outright price shifts. Therefore, the price elasticities for fuel oil are extremely
difficult to calculate and are often nonsensical, so a judgmental approach to power demand isusually required.
Emissions regulations are likely to further complicate oil demand projections, and particularly
those of fuel oil use. The IEA’s Medium Term Gas Market Review indicated the potential for gas
market tightness in key areas beyond 2010, as natural gas-fired power generation capacity expands
at a level that may be incompatible with regional supply growth. Typically, short-term power
generation issues are often resolved by turning to fuel oil as a temporary fuel source. Beyond 2010,
however, considerable investment in refinery upgrading capacity may lead to a tightening of thefuel oil market.
With emissions regulations making it difficult to restart old coal power generation plants, thereis the potential for sharp upward price pressures in both fuel oil and natural gas prices, which would
be felt across the petroleum sector. With the refining industry effectively converting fuel oil intotransportation fuels at that point, any increase in fuel oil demand would lead to a decrease in the
supply of transportation fuels. Ultimately, tightness in natural gas supplies could lead to a tightening
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gasoline balance. The question that arises, therefore, is at what point (if at all) would governments
decide that it is better to suspend emissions constraints to allow idled coal generation capacity, if thealternative were sharply rising oil and gas prices or power shortages.
The petrochemicals industry is another area where there can be significant inter-fuelsubstitution. While there are some instances where natural gas and biofuels have substituted oil
product inputs into petrochemicals, substitution generally occurs between different petroleum
products. LPG, naphtha, gasoil, NGLs and condensates can all be largely interchangeable. The
demand for these products will be related not only to their relative price, but also to theiravailability, which in turn can be related to the demand for other products, available capacity andnatural gas investments. Again, these differences mean that price elasticities for these products
require an in-depth understanding of the sector, together with a necessarily judgmental approach to
demand.
Substitution, however, is not simply an input effect. For example, significant shifts have been
seen away from base metals to plastics in recent years in two key areas – construction andbeverages. The popularity of the PET bottle has displaced aluminium demand from the canningindustry. Pet bottles have the twin advantage of lower weight and resealability – benefits for
consumer, distributor and marketer. Similarly, in the construction industry the rampant rise of
copper prices in recent years has led to significant market penetration of plastics in domestic andindustrial plumbing. Both examples are areas where innovation, availability and price could
significantly affect oil demand patterns in years to come – particularly in the petrochemical sector.
Similarly, waste management in many OECD countries is putting pressures on the use of plastics inpackaging and other areas – again, an area where substitution may be induced in a relatively shortperiod of time.
1.5 Subsidies
A further area of forecast uncertainty is fuel subsidies. Price and income effects tend to belarger in developing economies, but with state-administered prices prevalent in a large number of
populous non-OECD consuming countries, the spot price is not necessarily reflective of local
market conditions. Indonesia provides a good example of the impact and uncertainty caused byheavy oil subsidies, which at current prices are expected to cost in excess of $5bn/year. An attempt
to raise oil prices in 2005 led to significant social unrest, and had to be partially undone shortly
afterwards. As prices rose, there were significant swings in local demand, but with smuggling in theregion commonplace, it was difficult to determine how much of the demand swing was related topre-emptive local stockpiling and reduced smuggling and how much final consumption was
lowered. The rapid rise in oil prices in 2006 meant that subsidies were effectively re-introduced.
Indonesia is perhaps a micro-study of regional uncertainty, and the prevalence of (lesser) subsidies
in China and India means that price effects could be much larger at some point in the future,
therefore distorting demand growth. The Middle East is a further key demand growth area wherefuel prices are heavily subsidised. Again, although domestic pressures to liberalise prices are less(due to rising oil incomes), the policy shifts could alter the path of demand via price effects.
1.6 Economic growth
The IEA demand forecasts are based on GDP projections derived from work undertaken by the
IMF and OECD. They are subject to forecast uncertainty, which has been covered extensively by
the agencies themselves. At the present time, both agencies warn there are considerable
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uncertainties to the downside, which confer similar downside risks to oil demand. From a longerterm perspective, unless the trend in GDP growth alters dramatically from the projection, cyclicalswings are likely to even out. In a five-year time horizon, a recession or boom could considerably
alter the projected outcome.
Immigration is a further issue to consider. The expansion of the EU has led to widespreadworker migration, leading to rapid population expansions in wealthier countries. With oil income
elasticities being driven by income per capita changes, shifts in migration could have an important
impact. In the UK, for example, our assumption of relatively static population growth may be toolow. Migrant worker growth may have added several million to the UK population over the past few
years, while one study group projected that the higher birth rates of migrant workers could lead to asignificant population increase in the next 20 years. Such shifts in worker migration could raise percapita GDP, and could distort growth rates. Similarly, some studies have attributed recent growth in
US gasoline demand to shifts in migrant workers. Ultimately, though, in the case of many countries
we may have to wait ten years for accurate census data on the population to provide a benchmarking
snapshot.
1.7 Data
Turning to forecasting uncertainties, in addition to those surrounding future economic growthand oil price evolution (notably at the retail level), the predictive power of any demand forecast islargely dependent upon the availability and quality of the historical data underlying the projections.
In countries where the collection of detailed oil statistics is still in its early stages, both data (andrevisions) may be inaccurate. This may lead to an over- or understatement of demand, thus
distorting the calculation of income and price elasticities upon which the forecasting model is based.
In the case of Asia, for example, revisions have tended historically to be upward, suggesting thatcurrent demand may be understated. Moreover, many non-OECD countries do not include stock
data, obliging analysts to estimate demand on an ‘apparent’ basis.
Supply-side data is far from perfect, but historically, the larger revisions have come from thedemand side. This is partly due to the fact that in many areas, national supply-side data can be
double-checked with results from oil companies. In many cases in non-OPEC countries, supplies
can be aggregated independently on a field-by-field basis. However, that is not the case for all
countries. A lack of field data and a lack of detailed and consistent methodology for reserve
reporting makes estimates for rates of decline in production difficult in many regions.
Similarly, it is clear that at times, politics have played a role in reserve estimation in some
OPEC countries. During the late 1980s and early 1990s reserve levels within the producer group
had an influence on daily production targets. At that time, there seemed to be an increase in provenreserve levels, more to maintain market share than through technological innovation or discovery.
Demand, however, typically relies on accurate reporting from the refining, distribution,
stock-holding and import/export sectors to central government data collection. The Joint Oil Data
Initiative (JODI) is a welcome attempt to improve data availability and quality. Nevertheless,despite the efforts of its members (IEA, OPEC, APEC, UNSD, OLADE and Eurostat), the statisticalbalancing item in the Oil Market Report (“miscellaneous-to-balance”) has been rising in recent
years. There is clearly some way to go – the more so if the miscellaneous-to-balance item turns out
to be due to under-reported demand.

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Understandably, therefore, much of the data uncertainty focuses on non-OECD countries, andin particular, the major growth regions of Asia and the Middle East. Given China’s status as theworld’s second largest oil consumer and rapid oil demand growth, the fact that its energy balance issubject to close scrutiny is only natural. While data has improved – quality is significantly better
than many other countries with a similar level of GDP per capita – China still needs to take several
key steps: 1) release primary (refinery level) commercial and strategic stock data; 2) survey“teapot” refinery activity; 3) revise data, particularly that pertaining to trade figures; and 4) explain
why Chinese refiners achieve a volumetric processing loss, while European and US refiners withsimilar equipment achieve refinery gains.
These data inconsistencies – probably due to the lack of free-market pricing throughout the
supply chain, which provides incentives to distort data reports – make it difficult to assess China’s
oil demand. For example, news reports suggest that teapot refiners are supplied with domestic
crude, which is unreported on both the supply and demand side – possibly amounting to around150-250 kb/d in 2007. Similarly, customs data has sometimes shown no crude exports in aparticular month, despite evidence of effective loading and sailing of cargoes.
The IEA estimates Chinese demand on the basis of refinery output plus net product imports,
adjusted for direct crude burn and the use of teapot refineries. However, it could also be calculated
by adding domestic crude production, net crude and net product imports. This latter methodology,
though, does not enable the disaggregation of demand on a product-by-product basis and tends tooverestimate demand if stock-building is significant. Having to choose between both methodologies– which by definition include some arbitrary assumptions and hence can lead to different results –we believe the first one, during a period where China is building strategic oil stocks, is perhaps
more accurate, since it allows us to track each product.
India, meanwhile, has the potential to see a surge in energy demand, and presents datareporting issues which complicate the understanding of regional energy balances. Indeed, local
analysts suggest that coastal imports outside of main consuming areas may be under-reported,
therefore leading to a lower recorded demand. In addition, the widespread adulteration of dieselbased fuels can lead to distortions of inter-product demand. Last but not least, there is no reliableof commercial stock data.
In the Middle East, reporting qualities vary. While data from certain countries, Saudi Arabia inparticular, is very comprehensive on the demand side, in others, demand data collection is in its
infancy. Large price subsidies lead to extensive smuggling.
1.8 Biofuels
Automotive biofuels represent a further uncertainty, although it is rather contentious whether
or not they should be regarded as a demand-side uncertainty. From the perspective of demand
forecasting, biofuels are only significant in that the lower volumetric energy content of ethanol andbiodiesel supplies needs to be accommodated in our projections. However, biofuels are importantwith regard to the petroleum-liquids they displace.
Over the medium-term, biofuels supply and demand will broadly match, but this is notnecessarily the case over the short term. Automotive biofuels production capacity is expanding
rapidly, sometimes at a rate faster than the mandated level refiners are required to blend. This could
lead to short-term imbalances. In addition, the rapid expansion of biofuels production capacity is
tightening feedstock markets and therefore raising their price, posing questions over whether
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sufficient feedstocks will be available at an economic rate to meet capacity growth projections.
Given these caveats, our biofuel supply projections are around 1 mb/d below planned capacity
expansions by 2012.

2. SUPPLY-SIDE UNCERTAINTIESThe MTOMR projects strong non-OPEC liquids (crude, condensate, NGLs and biofuels)
supply growth in 2007-2009, appearing to recede thereafter as the slate of verifiable investment
projects diminishes. Total non-OPEC liquids supply growth to 2012 is pegged at 2.6 mb/d. The
report estimates that around 3 mb/d of new production is needed each year to offset the effects ofdecline. This equates to net oilfield decline rates averaging 4.6% annually for non-OPEC and 3.2%
per year for OPEC crude. Aggregate levels mask much sharper declines in a 15-20% per annum
range for mature producing areas and for many recent deepwater developments. Further, oursupply-side estimates incorporate a new 0.4 mb/d contingency factor, reflecting a tendency forunscheduled field outages.
Supply-side uncertainty is further
Medium-Term Supply/Demand Growth
exacerbated by increasing instances ofmb/d
3.0
resource nationalism and geopolitical risk,
constraining the ability of the industry to
expand output. Upstream construction,
2.0
drilling and service capacity will remain
stretched for some time, leaving forecasts
1.0
prone to slippage, due to cost over-runs andproject delays. On balance, these aboveground risks are seen as greater than those
0.0
posed by resource depletion and other
2007
2008
2009
2010
2011
2012
Non-OPEC Growth (excl. Biofuels)
Biofuels Growth
below-ground factors. Overall, this leads to
OPEC NGLs Growth
OPEC Capacity Growth
average non-OPEC supply growth of 1.0%
World Demand Growth - Ave 4.5% GDP
Low Demand- Avg 3.2% GDP
High Demand - Avg 5.9% GDP
between 2007 and 2012, 0.4% below thegrowth seen in the previous seven years androughly half the rate of global demand growth projections.
Ultimately, there are the natural resources to boost output in the medium term, but there areconsiderable questions about whether the above ground access, service sector resources and IOC
investment plans will deliver. With this in mind, substantially higher cash returns to shareholders
stand in curious contrast to growing upstream supply tightness and essentially unchanged
exploration and production (E&P) effort. Nominal E&P expenditures are up, but higher costs haveeroded their purchasing power commensurately. However, it is clear that there are other issues atwork.

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MEDIUM-TERM OIL MARKET UNCERTAINTIES -159

In particular:•

Access and contractual conditions (even in OECD countries) are deteriorating.

•Hurdle rates for upstream investment may be too conservative (development costs have
moved higher, albeit there are indications that cost inflation may be stabilising).

•

Labour, equipment and service sector constraints may reduce the potential for expansionof the project base, at least through 2012.

•

The rise of consumer-country NOCs and independent exploration companies is eroding
the market share of more risk-averse IOCs, which endured years of lower returns after theoil price collapsed in the mid-1980s.

2.1 Project slippage
Project slippage is a major issue for supply-side projections. In the five months between the
publication of the February MTOMR update and the 2007 MTOMR in July, over 3.2 mb/d of new
projects in the 2007-2011 period saw their timing slip, emphasizing the scale of the problem.
Slippage varies between two and 36 months, but is typically around six months. Given the extent of
the problem, project timing assessments have been dealt with more aggressively, particularly withthose where delay is most likely. Nonetheless, shortages of labour, raw materials, fabrication anddrilling capacity and transport infrastructure may continue to undermine output growth for sometime.
2.2 Decline rates
An average global decline rate is a useful rule of thumb, but one which can be over-used. Froma field by field forecast, it is clear that decline rates can vary hugely even between fields in similar
locations. There is a constant ebb and flow of fields entering decline, offset by others where decline
is reversed by the application of EOR or satellite developments.
A proxy can be calculated by comparing net change in non-OPEC supply for 2007-2012 andgross capacity additions. The implied net non-OPEC decline rate for baseload production is around
4.6% per year. This covers not only fields in decline, but also older supply which is at or
approaching plateau. With net decline from OPEC assumed at 3.2% per year, this gives a global
annual decline of 4%, suggesting that 3.2 mb/d of new production must be found each year just to
stand still. Moreover, this net global decline for existing assets masks fairly aggressive assumptions
for parts of the OECD and for deepwater projects elsewhere. Development schedules for the lattercan show rapid ramp-up followed by abrupt annual decline in a 15-20%-plus range.
Decline rates clearly hold the potential for significant oil supply forecast uncertainty. Ourderived net decline of 4.6% per year results in non-OPEC oil supply (excluding biofuels andprocessing gain) in 2012 of 48.8 mb/d. Increasing that decline rate to 5% would net 875 kb/d off thetotal, and a range of decline rates from 2% to 7% swings 2012 non–OPEC supply by 11 mb/d intotal.
Without minimising the importance of this variable, particularly given a shortage ofcomprehensive field-specific production and reserves data, our analysis suggests that variance fromthe original non-OPEC forecast in recent years has not primarily been due to understatement of fieldOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 - © OECD/ITF, 2008

160 – MEDIUM-TERM OIL MARKET UNCERTAINTIES
decline rates. Rather, we believe that project slippage, weather, and unplanned production stoppages
for technical, economic and geopolitical reasons, have been, and will continue to be in the next five
years, the main risk factors. Put another way, while we continue to monitor and actively adjust for
shifts in field and aggregate decline, we see above-ground risks more prevalent, for now, thanbelow-ground risks.
The concept of peak oil production and its timing are emotive subjects which raise intense
debate. Much rests on the definition of which segment of global oil production is deemed to be at or
approaching peak. Certainly our forecast suggests that the non-OPEC, conventional crude
component of global production appears, for now, to have reached an effective plateau, rather than apeak. Having attained 40 mb/d back in 2003, conventional crude supply has remained unchanged
since and could do so through 2012. While significant increases are expected from the FSU, Brazil
and sub-Saharan Africa, these are only sufficient to offset declines in crude supply elsewhere. Putanother way, all of the growth in non-OPEC supply over 2007-2012 comes from gas liquids, extra
heavy oil, biofuels (and, by 2012, 145 kb/d of coal-to-liquids from China). As overall non-OPEC
liquids capacity increases, this plateau reduces the share of non-OPEC conventional crude supply
from 77% in 2000, to 74% in 2006 and 67% in 2012.
While there might be a temptation to extrapolate this trend, citing a peak in conventional oil
output, a degree of caution is in order. Firstly, the concept of “conventional” oil changes with time,
technology and economics. In the early 1970s, much offshore production was deemedunconventional, but this portion of global supply has since grown to account for 30% of the total.
Evolving economies of scale and infrastructure development could do the same for GTL, oil sands
and ultra-deepwater reserves in the future, shifting today’s unconventional resource into tomorrow’s
conventional supply category. Moreover, rapidly-growing condensate and NGL supply is scarcely“non-conventional” in a technical sense now.
We also note that for certain regions, notably the FSU and West Africa, the turn of the current
decade is likely to mark a hiatus in crude supply growth. Strong growth is expected to resume here
towards the middle of the next decade. Whether this will be sufficient to offset the declines
expected for mature OECD crude supply, preventing overall decline for non-OPEC, is less easy to
predict.
Finally, we note that focussing on non-OPEC crude alone is a rather selective way of
considering the sustainability of global oil production. Peak or plateau production is frequently
taken as shorthand for impending resource exhaustion. While hydrocarbon resources are finite,
nonetheless issues of access to reserves, prevailing investment regime and availability of upstream
infrastructure and capital seem greater barriers to medium-term growth than limits to the resourcebase itself. Critically, our belief that above-ground factors rather than resource constraints are thekey impediment to capacity expansion holds out the possibility that the recent slowing of capacity
growth could be reversible.

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3. INVESTMENT

3.1 Prices
Over the very long term, the economic threshold at which oil companies invest in upstream
projects is likely to reflect prevailing oil prices. However, the extreme constraints in the oil services
sector have led to rampant cost inflation. Exploration and Production budgets, while expanding
rapidly, have therefore failed to deliver a proportional increase in E&P activity. While we believethat this is a cyclical phenomenon, related to labour and equipment shortages and rising commodity
prices, it is not a situation that leaves itself open to modelling. Therefore, on the supply side, ourforecasts are based on the premise that the spot oil price remains above the marginal cost of
production for the medium term, therefore encouraging the recent increase in E&P activity from thelow levels seen for much of the previous fifteen years. However, while it is clear that strong
investment will be required over the longer term, medium-term investment decisions may be subject
to cyclical industrial and economic effects.
3.2 Operating environment and constraints
Net supply projections are the result of “push and pull” between various factors, which clearlyvary over time and often require subjective judgement. The MTOMR characterises the upstream
operating and investment environment for 2006-2011 as follows:
1.
2.
3.
4.
5.
6.
7.
8.

Rising crude oil price assumptions employed by operating companies;
Increasing spending and activity levels;
The expanding reach of consumer country NOCs;
A declining trend in exploration expenditure as a share of IOC total spending;High costs and tightness in construction, drilling and service capacity;
Correspondingly, a tendency for new upstream project delays;
A compounding impact of delays to new pipeline and gas processing capacity;
Proliferating geopolitical risks and barriers to oil company access.

Arguably, the first three factors could accelerate the pace of expansion in non-OPEC andOPEC supply. However, the balance of risks deriving from factors 4-8 lies heavily on the downsideand would seem to argue for slower growth in global production capacity relative to historical
trends.
These trends are clearly changing. For example, NOCs and governments are broadly
budgeting for an average economic threshold of $45/bbl (versus $35/bbl a year ago), withinternational company and independent producer price assumptions levelling off close to $55/bbl.
However, in some cases, new projects are still being tested at prices down to as low as $35/bbl.
Clearly this leaves room for a growing portfolio of feasible projects with current oil prices over$90/bbl.

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162 – MEDIUM-TERM OIL MARKET UNCERTAINTIESWith rising prices, spending levels have increased. Industry spending surveys by Lehman
Brothers and Citigroup suggest ongoing growth in upstream activity, notably outside of North
America. Increases in expected capital expenditure in 2007 lie in a 10-15% range, with similar
growth for 2008. However, many of these spending increases have been mitigated by rising
upstream development and service sector costs.
In many ways, parts of the current supply cycle stretch back to OPEC supply management in
the 1970s and 80s, which led to a sharp increase in OPEC spare capacity as market share waseroded by expanding non-OPEC supplies. The resultant supply overhang helped to keep prices
relatively low, cyclically prompting IOCs to curb exploration, outsource service-sector roles and cut
research and development. OPEC spare capacity was reduced, which meant that when the 2004
demand surge hit, the industry was left with few resources with which to respond.
It takes time to rebuild such capacity, and while high wage rates are attracting more engineers
into the field, labour constraints are unlikely to ease significantly into the next decade. But it has tobe recognised that this is not simply an oil-related issue. Production expansions of many natural
resources are being constrained by similar factors. Equipment tightness is prevalent in manyindustries, and particularly in other energy sectors. Silicone shortages are limiting the expansion ofsolar panels, wind power generators are suffering from turbine shortages, and base metal prices areat record highs.
Cost inflation for raw materials, service and drilling capacity shows some signs of moderating,although industry consensus points to a levelling in upstream costs rather than a substantial fall.
Healthy spending increases have therefore largely been absorbed by double-digit inflation, limiting
any automatic feed-through of high prices into incremental discoveries and production. The rise in
exploration’s share of upstream spending has been modest, and company reserve replacement rates
remain weak, despite sustained high prices. This can be partly explained by access and regulatory
uncertainty; in turn, partly related to a spate of resource nationalism.
Drilling indicators for oil remain positive. While there was a sharp decline in drilling activity
in 2Q07 this was largely due to a collapse in Canadian natural gas drilling due to weaker gas prices.
It is estimated that deepwater drilling capacity will remain constrained for another 18-24 months
before substantial new capacity is activated. However, given that much of the projected increases in
production are seen coming from the likes of Brazil, GOM, northern Russia, the Caspian andWest Africa, the potential for additional slippage clearly compounds supply-side risks.
Delays in natural gas expansion are another factor that can be added to the list of potential
forecast risks. For the Middle East and Russia, the IEA’s Natural Gas Market Review has identified
insufficient upstream investment. This undermines not only natural gas liquids (NGL) supply, butalso oilfield reinjection of associated gas, potentially impeding crude oil production rates. That said,as producers recognise potential future shortages in gas for domestic or export markets, so efforts toboost supply by cutting gas flaring and transmission losses should intensify.
The price signals are there but service sector capacity will take time to expand and, until it
does, the market will be slow to respond. Even when this cycle has ended, there needs to be
sufficient access to reserves to prompt a supply response. Further, the price incentives need to behigh to persuade oil companies to take the significantly higher risks of exploration.

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MEDIUM-TERM OIL MARKET UNCERTAINTIES -163

3.3 OPEC supply
In the MTOMR, OPEC producers are expected to add a net 4.0 mb/d to installed crude
capacity during 2007-2012. The years 2008 and 2010 see particularly strong growth, when new
project start-ups drive OPEC capacity higher by over 1.0 mb/d in both years. The forecast takes
account of new capacity investments and net decline from older fields (decline rates are assumed torange from 1-5% per annum for onshore fields in the Mideast Gulf, through to 12-15% p.a. fordeepwater fields). Overall, net decline for the group as a whole averages 3.2% annually, lower than
the 4.6% evident from the non-OPEC forecast. This reflects in part the predominance of lowerdecline onshore and shallow water production in the total (although deepwater production from
Angola and Nigeria is taking on greater importance). OPEC therefore faces the task of replacingsome 1.1 mb/d each year just to sustain capacity at existing levels.
Political and security issues also confer considerable risk to the supply forecast. The MTOMR
assumes limited growth in Venezuela, Iran and Iraq, while in Nigeria a portion of long-term outages
have been assumed to continue to reduce effective spare capacity. Changes to current conditions are
difficult to predict, but it is fair to argue that a resolution of security issues in Iraq and Nigeria could
result in a significant expansion in OPEC capacity.
Looking at OPEC crude additions for 2006-2012 tells only half the story for potential capacity
growth. Gas liquids (ethane, propane, butane and pentanes from gas processing plants plus field gas
condensates) are expected to rise by +2.2 mb/d (+7.8% pa) and take potential OPEC NGL supply to
7.1 mb/d by 2012. The rate of increase matches growth evident during 2001-2006, as attempts toboost natural gas utilisation and to reduce flaring continue.
While there is considerable uncertainty over the level of OPEC reserves and decline rates, as
great an issue for projected oil market balances in the coming decade is how OPEC countries
choose to manage their reserves. What will a country decide is its optimum production rate? There
have been suggestions that Saudi Arabia, for example, will limit its crude supply expansion to a
maximum of 15 mb/d. Regardless of how China or India’s future car pool is calculated, and whatlevel of demand growth is implied, quite simply, it will not materialise if the supply is not there in
the short- to medium-term.

4. CONCLUSION

Considerable forecasting risks remain on both oil supply and demand. Some of these risks canbe better understood by improvements to data quality and coverage. Improved transparency will not
augment supply, but it can help to improve the robustness of supply-side projections. However,arguably some of the largest uncertainties facing the oil world stem from non-oil data issues.
On the demand side, the rate of growth of oil consumption depends heavily on the rate of
economic growth in highly populous developing countries such as China, India, Indonesia andBrazil. There would be a considerable difference to outcomes if Chinese economic growth were tostall, rather than continue growing at its current 10% annual rate. Similarly, these countries will
eventually reach a point where growth rates moderate, thus slowing demand-side pressures.
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164 – MEDIUM-TERM OIL MARKET UNCERTAINTIESDemand may also be constrained by an accelerated policy effort to reduce emissions. Policy andprices can alter the speed at which technological innovations occur and are incorporated.
But demand projections can only be realised if there is the supply there to meet them. National
resource management policy is perhaps the hardest area to forecast. At what point a country decides
its extraction rate is optimised will depend upon many factors, including prevailing price levels andthe resource base. Security and political shifts can result in this factor becoming a moving target.
Ultimately, though, even if supply constraints are less than envisaged, the demand potential fromemerging economies is very significant, and in the foreseeable future there is little prospect of asignificant shift away from petroleum-based fuels in the transportation sector. Whether constraints
are derived from the supply or demand side of the equation, environmental considerations are afurther reason to justify the need to prepare for a constrained transportation fuel market – even if thefuel is there, there are reasons we may not wish to use it.

NOTE

1.

The New York Stock Exchange’s Intercontinental Exchange. ICE’s energy futures business is run
by its London based subsidiary, ICE Futures Europe.

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LONG-RUN TRENDS IN TRANSPORT DEMAND -165

LONG RUN TRENDS IN TRANSPORT DEMAND,FUEL PRICE ELASTICITIES AND IMPLICATIONS OF THE OIL OUTLOOKFOR TRANSPORT POLICY

Kenneth A. SMALL
University of California at Irvine
California
USAandKurt VAN DENDER
University of California at Irvine/
Joint OECD/ITF Transport Research Centre
Paris
FranceOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 - © OECD/ITF, 2008

LONG-RUN TRENDS IN TRANSPORT DEMAND -167

ABSTRACTThis paper discusses the role of transportation in policies to address energy security and climatechange. It focuses on three elements: the impact of energy prices on transport demand, the potential
contributions of the transport sector to energy policies, and the interaction between energy and otherpolicy concerns in transport. Transport is relatively unresponsive to broad-based price signals, inparticular to changes in prices of fuels, but nevertheless there is considerable scope to improve thefuel efficiency of vehicle fleets. As a result, we should not expect energy policies to trigger dramaticchanges in the nature of transport systems. Furthermore, this unresponsiveness suggests that it isrelatively costly to reduce energy use in transport, and thus that efficient policies will probably not
extract as much energy saving (in percentage terms) from transport as from other sectors. Reducing
energy use in transport can be done with price incentives or with regulatory measures. But if
reducing climate change is a primary goal, measures that mandate conservation need to beaccompanied by others that make fossil fuels economically unattractive – for example broad-basedcarbon taxes. Otherwise, fossil-fuel reserves will remain economically usable and therefore will
constitute a future source of carbon dioxide emissions. We argue that other transport problems,
notably congestion, local air pollution, and accidents, are associated with considerably higher
marginal external costs than are climate change and energy security. It follows that policies to deal
directly with these other problems deserve high priority, regardless of energy policies.

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LONG-RUN TRENDS IN TRANSPORT DEMAND -169

SUMMARY

ABSTRACT ........................................................................................................................................ 167
1.

INTRODUCTION ........................................................................................................................ 171

2.

THE DETERMINANTS OF ROAD PASSENGER TRANSPORT DEMAND AND
DERIVED ENERGY DEMAND IN THE LONG RUN ............................................................ 172
2.1 Trends in the US, 1970-2005 ................................................................................................ 172
2.2 Trends in other IEA countries ............................................................................................... 176
2.3 Future developments ............................................................................................................. 176
2.5 Summary ............................................................................................................................... 182

3.

ENERGY POLICY IN TRANSPORT ......................................................................................... 183
3.1 Marginal external costs of motor-fuel consumption due to climate change ........................ 186
3.2 Marginal external costs of motor-fuel consumption due to oil dependency ......................... 188
3.3 Implications of analysis of marginal external costs .............................................................. 190

4.

CONCLUSION ............................................................................................................................ 191

NOTES ................................................................................................................................................ 192
BIBLIOGRAPHY ............................................................................................................................... 196

Irvine and Paris, December 2007

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LONG-RUN TRENDS IN TRANSPORT DEMAND -171

1. INTRODUCTION

Recent years have seen the re-emergence of public debates on the desirability of managing
energy consumption and on the effectiveness of various ways of doing so, in transport and othersectors of the economy. The impetus for increased interest in energy issues is twofold. First, oil is aprime source of energy, so that high and volatile oil prices and increased dependence on oil imports
have strengthened concerns regarding energy security. Long term projections for oil prices are on
the rise. For example, in 2000 the International Energy Agency used a price of $33/barrel for its
baseline projection for 2030 (prices of 2005); in 2004 the figure was $40, and in 2005 it had risen to$55, reflecting a concern that higher oil prices are not a transitory phenomenon.1 The second
impetus is a growing consensus that the expected costs of climate change warrant measures toreduce greenhouse gas emissions, although just how quickly remains controversial (e.g. Arrow
2007, Schelling 2007).
The goal of this paper is to assess three factors: the impact of expected higher energy prices ontransport demand, the potential contributions of the transport sector to energy policies, and theinteraction between energy and other policy concerns in transport. Our focus is mostly on roadpassenger transport because it is a particularly large energy consumer and is often targeted forenergy policies.
Section 2 starts with a review of past trends and projections for the future. Nearly all sourcessuggest continued strong growth in transport demand everywhere, especially in developing
countries like China. This demand growth is part of the reason why oil prices have increased; buthigher prices so far have not tempered growth much because their effects have been swamped bythose of population and income.
Section 2.4 provides a more analytical perspective to determine the main factors driving
energy demand in road passenger transport. We review recent econometric evidence, especially for
the US, paying particular attention to studies that distinguish explicitly the components of fuel use(vehicle stock, average vehicle mileage, and average fuel economy). This review confirms that
income is a key driver of transport demand; fuel prices matter as well, but less so. In addition, theimpact of the fuel cost of driving, both on the demand for driving and on the demand for fuel,appears to decline as incomes rise. A consequence is that the impact of fuel prices on fuel demand
works increasingly through fuel economy improvements rather than through reductions in theamount for driving.
A broad conclusion from section 2 is that the elasticity of demand for oil will very likely
decline. A consequence is that fuel taxes would need to increase more strongly in order to curb fuelconsumption by a given amount. This does not affect the economic case for fuel taxes overalternative policies, but it does affect their political feasibility. When high fuel taxes are notpolitically feasible, then regulations of fuel economy become more attractive. In this sense, lower
elasticities are “good news”, as the increased driving resulting from the lower fuel cost of driving
caused by better fuel economy – the so-called “rebound effect” – is limited; this of course enhances
the effectiveness of fuel-efficiency regulations in achieving their objective of reducing fuelOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 - © OECD/ITF, 2008172 – LONG-RUN TRENDS IN TRANSPORT DEMAND
consumption. So, from the perspective of energy security, policy responses that mandate improved
fuel economy seem to make sense. But if the goal also is to reduce greenhouse gas emissions, such
regulations probably should be complemented by fuel or carbon taxes, because better fuel economy
in itself may primarily alter the time pattern of oil usage rather than its cumulative total.
In section 3 we discuss the interaction between energy and other policy concerns in thetransport sector. Energy policies affect transport problems, like local air pollution and congestion,
which are more closely linked with the amount of driving than with the amount of fuel consumed.
One implication is that even small increases in the amount of driving, resulting from fuel economy
regulations that reduce fuel consumption, may have costly side-effects. Policy measures to control
these side-effects are warranted, and some are in place: for example, local air pollution is controlled
through per-mile emission limits. But apart from a few well-known cordon pricing schemes(Singapore, London, Stockholm) and some value pricing experiments (Southern California, Texas,
Minnesota), congestion is largely uncontrolled.
In thinking about transport policy more broadly, one needs a yardstick by which to compare
the importance of the various goals being addressed. We focus on one such yardstick: the marginalexternal costs of motor vehicle use from various sources. Using this, we find that more prosaic
problems such as congestion, air pollution, and motor vehicle accidents demand a higher priority
than energy problems as we search for ways to improve transport. We also suggest that transport isprobably a sector of the economy that should contribute less than proportionally to reductions inenergy use, as other sectors offer cheaper opportunities for fuel switching and conservation. Thesefindings do not negate the significance of energy policy in transport, but they do offer a caution thatenergy must not become the only, or even the primary, consideration.

2. THE DETERMINANTS OF ROAD PASSENGER TRANSPORT DEMAND AND
DERIVED ENERGY DEMAND IN THE LONG RUN

In this section, we review the main determinants of demand for passenger transport using
motor vehicles, with a focus on energy consumption. We pay special attention to the US (section2.1), which is the world’s largest consumer of energy for transport purposes and for which abundantdata are available. In section 2.2, we briefly consider trends in other countries, and in section 2.3 welook at projections and policies for the next few decades. In section 2.4, we consider evidence on
the price sensitivity of transport demand for energy, including its size, manner of variation, and thedecomposition of this price response into changes in the amount and the energy intensity of travel.
Lastly, section 2.5 summarizes the insights obtained.
2.1 Trends in the US, 1970-2005
We first discuss trends in energy use and then look at its components (vehicle stock, fuelintensity, and mileage). The Transportation Energy Data Book (Davis and Diegel, 2007)
conveniently collects the relevant data.

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LONG-RUN TRENDS IN TRANSPORT DEMAND -173

Transport relies on petroleum, and usage keeps increasing
Petroleum consumption by all sectors in the US increased from 17.3 million barrels per day(mb/day) in 1973 to 20.8 mb/day in 2005.2 That growth was not uninterrupted: consumption hit a
low of 15.2 mb/day in 1983. Petroleum consumption from transport, however, grew steadily, from9.05 mb/day in 1973 to 13.9 mb/day in 2005; consumption fell in all other sectors (residential,commercial, and electricity) except the industrial sector, where it grew slightly. As a consequence,the share of transport in total petroleum consumption grew strongly, from 52% in 1975 to 67% in
2005. The share of transport in total US energy consumption also grew, from 24.6% in 1973 to
28.2% in 2005. Transport relies almost exclusively on petroleum for its energy, with a 96% share in1973 and in 2005. The petroleum shares are much lower, and declining, in other sectors.3
These numbers illustrate that transport has not substituted out of petroleum, in contrast to othersectors. Combined with the fact that petroleum is relatively highly taxed in transport, this suggeststhat technological substitution to other sources of energy is particularly difficult in transport. An
alternative response to high oil prices is to improve fuel economy. Such responses have taken place,in part because for some transport modes, the market mechanism has been complemented byregulatory interventions, most notably the corporate average fuel economy (CAFE) regulations on
new passenger vehicles. But these responses have not been sufficient to offset the strong growth intransport activity.
Light-duty vehicle energy use dominates transport energy use
Next, we consider the breakdown of transport energy use by mode, expressed in trillions ofBritish Thermal Units (btu); see Table 1. While total energy use in transport increased by 78%
between 1970 and 2005, that increase was much more pronounced for highway modes (88%) thanelsewhere (45%). The greatest growth was for light trucks, partly induced by the CAFE
regulations;4 but growth was substantial in the overall light vehicle fleet as well. Energy use byheavy trucks and aviation grew rapidly as well. Cars and light trucks together accounted for justunder two-thirds of all transport energy use, in 1970 as well as in 2005. The shares accounted for byheavy trucks and aviation rose, while those of most other modes declined.
Energy intensity has declined strongly for most modes
Table 2 shows how energy intensity has evolved in transport, leading to several observations.
First, all modes except water-borne freight are considerably more fuel efficient in 2005 than in
1970. Second, the strongest reduction in energy intensity occurred for commercial air transport,
probably because of increasing aircraft size, higher occupancy rates, and improved technology.
(General aviation did not share in this reduction.) On a per passenger-mile basis, commercial air
travel is now as efficient as driving a car, but of course air travel tends to be over longer distances.
Third, light trucks consume 1.4 times as much energy per passenger-mile as cars, even under the
optimistic assumption that occupancy rates for trucks are as high as those for cars. Fourth, fuelefficiency improvements are no stronger for regulated light-duty vehicles than for unregulatedmodes. This suggests that, if there is a basis for targeting light-duty vehicles for fuel-economy
regulation, it is that households make “worse” decisions on fuel economy than do commercial
transport operators like trucking firms or air carriers.5 Finally, buses are now less efficient perpassenger-mile than cars, because of declining occupancy rates.

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174 – LONG-RUN TRENDS IN TRANSPORT DEMAND
The number of light-duty vehicles and their usage increased on a per capita basis
In 1970 there were 0.48 vehicles per capita, against 0.80 in 2005; for the same years, averageannual per capita vehicle use increased from 5,440 to 10,087 miles. Business fleet vehicles are usedeven more intensively, at approximately 25,000 miles per year. The net impact is that total highway
travel in the US grew at a 3.2% annual rate for 1970–1995, and a somewhat lower 2.1% rate for
1995–2005.6 However, recent traffic data suggest that extended high gasoline prices can eventuallyinterrupt such trends: travel on all roads and streets apparently declined by 0.4% between April
2006 and April 2007.7 Thus high fuel prices can sometimes reduce travel by enough to outweigh thepositive (and possibly declining) effect of rising income.
The average trip length in the US has crept upward from 8.7 miles in 1983 to 10.0 miles in2001 (Pisarski 2006, Fig. 3-7). The average length of a work trip has risen considerably faster, from
8.5 miles to 12.1 miles during the same time period. Much of the growth in commuting trip length isdriven by a dramatic rise in suburb-to-suburb commuting trips and a less dramatic but still
important rise in commuting trips from suburbs to central cities (Pisarski 2006, Fig. 3-9). It isnoteworthy that only 22% of all trips are commuting trips (NHTS 2001). Trips for shopping and for
personal business now represent 46% of all trips; however, some of this travel is probably as hard to
avoid as commuting travel and harder to shift to other modes.
Summary
Improvements in energy efficiency are not strong enough to compensate for the rise in energy
demand caused by increased travel, so that transport energy use continues to increase. There are,however, recent indications that sufficiently high energy prices can slow the growth in travel
sufficiently to curtail energy use.

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102.5
107.8

1990
2005

289.2
526.8

9.99
20.61
29.61

Light
Truck

342.9
385.7

0.05
0.11
0.10

Heavy
All Hwy
Air
Water
Truck
% overall energy use
0.84
10.09
76.02
8.49
5.45
0.77
15.44
77.15
9.62
6.69
0.70
16.71
80.49
9.05
4.99
Change in energy use by mode, 1970 = 100
129.5
214.7
142.3
158.9
172.0
148.1
294.7
188.3
189.5
162.6

HighwayMotorBus
cycle

88.5
118.4

3.60
2.27
2.40

Rail

Freight
Transit bus
Cert. air carrier
Rail transitHT
ind. btu/pm
ind.
btu/pm ind. btu/pm
ind. btu/vm
100
2472
100
10282
100
2157
100
24960
93
2814
114
7826
76
2625
122
24631
82
2813
114
5561
54
2312
107
24757
75
3423
138
5053
49
2809
130
23343
72
3794
153
4875
47
3024
140
22795
67
4310
174
4349
42
3340
155
22096
68
4515
183
3952
38
2729
127
23448
73
na
na
3264
32
2784
129
20539

Rail
ind. btu/tm
100
691
99
687
99
597
94
497
91
420
89
372
94
352
82
337

Table 2. Energy intensity by mode (btu per “output mile”), USA, 1970-2005

93.2
85.1

6.43
4.27
3.07

Non Hwy
Pipe-line

Water
ind. btu/tm
100
545
99.4
549
86.4
358
71.9
446
60.8
387
53.8
374
50.9
473
48.8
514

133.7
144.7

23.98
22.85
19.51

All Non
Hwy

ind.
100
101
66
82
71
69
87
94

140.27177.84100.00100.00100.00All

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Legend: pm is passenger-mile, vm is vehicle-mile, tm is ton-mile
Source: Davis and Diegel, 2007, Tables 2.13, 2.14, 2.16
Note: Davis and Diegel, 2007, do not provide btu/pm for light trucks - we converted btu/vm using car occupancy rates (which are likely higher)

Passenger modescarLT
btu/pm ind. btu/pm
1970
4868
100
6709
1975
4733
97
6252
1980
4279
88
5527
1985
4110
84
5008
1990
3856
79
4842
1995
3689
76
4505
2000
3611
74
4545
2005
3445
71
4874

Source: derived from Davis and Diegel, 2007, Tables 2.7 and 2.8.

55.06
40.22
33.38

1970
1990
2005

Car

Table 1. Transport energy use (measured in btu): modal composition and change, USA, 1970 and 2005

LONG-RUN TRENDS IN TRANSPORT DEMAND -175

176 – LONG-RUN TRENDS IN TRANSPORT DEMAND
2.2 Trends in other IEA countries
Oil consumption for transport in all countries belonging to the International Energy Agency(IEA) grew from roughly 600 million tons of oil equivalent (Mtoe) to 1,000 Mtoe between 1970 and
2000. Growth in transport was steady, despite a drop in overall oil consumption in the late 1970s
and early 1980s (IEA 2001). Transport relies nearly entirely on oil as its source of energy(approximately 97% in OECD countries: IEA 2002).
Within surface transport, the pattern of energy consumption by mode tends to lie between two extremes: US
and Japan. The US has the highest share accounted for by cars and light trucks (66% in 1995), whereas
Japan has the lowest (52%). The situation is reversed for truck freight (29% share in the US, 38% in Japan)
and for passenger transport by bus and rail (just 1% in the US, 7% in Japan). Thus while the US stands out inits dominance of light-duty passenger vehicles, such vehicles account for the majority of energy consumption
for land transport in all IEA countries.

According to IEA (2001), new car fuel economy in the US was roughly on the same level as inJapan and Australia over the period 1980–2000. (It was considerably higher in Europe.) However,the fuel economy of light trucks, used mostly for passenger transport and especially prevalent in theUS, is much lower than that of cars. Overall fuel efficiency of passenger-vehicle fleets rosemodestly from 1980 to 2000 in most IEA nations; but in the US such improvements came to acomplete standstill in the late 1990’s, mainly because of the explosion of light truck use. Anotherway to look at this is that fuel use per unit weight has declined strongly everywhere, but vehicle
weight has increased, especially in the US.
Regarding travel demand, IEA (2002) shows that in several European countries (France, UK,
the Netherlands), vehicle-km per capita increased from roughly 3,000 to 6,000 between 1970 and
1997. This growth rate is greater than that in the US; however, since the level in these European
countries is still less than half that in the US, it does not seem likely that Europe will converge
anytime soon to US levels of per capita driving.
To summarize, patterns and trends in the US and other IEA countries are not fundamentallydifferent. However, the levels are quite different: the US exhibits persistently higher rates of vehicle
ownership and usage and lower fuel efficiency, the latter due in part to the higher prevalence oflight trucks in US passenger fleets.
2.3 Future developments
OECD countries now represent 70% of worldwide transport energy use; but according to IEA
projections this will decline to 55% in 2030 and to 45% in 2050. The growing share of transport inoil demand is not limited to IEA or OECD Countries, and it is likely to continue. Transport in 1997
already represented 54% of oil consumption in the OECD and 33% in the rest of the world; theseshares are projected to increase to 62% and 42%, respectively, by 2030 (IEA, 2006). Fulton andEads (2004) remark that the growing share of transport in total oil demand leads to a decline in theoverall price sensitivity of oil demand, because transport demand is less price-elastic than demandfor other energy services. This decline may lead to larger price volatility in response to supply
shocks, which in turn is one of the factors driving the recent surge of popular interest in energy
policy.
The growth in energy use can be decomposed into changes in transport demand and in theenergy intensity of vehicles in use. Eads (2006) projects that globally, light-duty vehicle usage willgrow by 1.9% per year for 2000–2050, while energy intensity declines by 0.4% per year; the net
result is that total energy demand for passenger transport will grow by 1.5% per year. For air
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LONG-RUN TRENDS IN TRANSPORT DEMAND -177transport, energy use grows by 2.6% per year, deriving from annual demand growth of 3.3% andfuel economy improvements of 0.7%. For trucks, energy use grows by 1.9% per year, with demand
increasing at a rate of 2.6% and efficiency improving by 0.7% per year. Projected growth is faster indeveloping countries, but vehicle ownership there is not expected to reach US levels by 2050, norwill per-capita transport demand reach OECD levels. The main driver for transport demand growthis per capita income. (The IEA assumptions about income growth imply roughly that by 2050, theformer Soviet Union, Eastern Europe, and China will reach OECD income levels of 2000, whereas
India will by 2050 reach the same level attained by China in 2025.)
Energy consumption in transport is a policy concern in many nations with large markets formotor vehicles. The US, Europe, and Japan use various combinations of fuel taxes, vehicle taxes,
and energy efficiency regulation of new cars, but the emphasis varies. Fuel economy is regulated inmany parts of the world, but it was introduced in the EU and in Japan only recently, and there is no
regulation in India and Mexico, where transport demand is likely to grow strongly in the near future(Plotkin, 2004). In addition, there are large differences in the stringency of fuel economy regulation,differences that are likely to continue (An et al., 2007). The EU and Japan have the most ambitious
targets. The US has laxer standards than most other countries, but the current policy impetus seems
to be towards stricter regulation. China plans to converge to the strictest standards, but will needtime to do so. Regulations are in place in Brazil and South-Korea, but they are not very ambitious.
An et al. (2007), reviewing policy developments, suggest that there is increasingly widespreadreliance on fuel efficiency regulations. A main reason is that further increases in fuel prices arepolitically difficult – in rich countries because they are mostly high already, and in poor countries
because of concerns about equity (and, we would add, because of political stability). Thus, it isreasonable to expect further regulation-induced declines in the fuel intensity of motor vehicles inmany parts of the world.
While increased fuel-efficiency regulations may generate benefits, their value in mitigatingclimate change is reduced by the fact that they affect the timing, rather than the cumulative amount,of emissions from fossil fuels. The advantages from lowering greenhouse-gas emissions today will
to some extent be at risk in the future as the unused stock of fossil fuels remains attractive
economically in the absence of measures to raise its price. Strong investments in the efficiency of
conventional, carbon-intensive transport technology will if anything tend to reduce the price offossil fuels – indeed, when the discussion turns to energy security that is one of its explicit purposes.
Many analysts seem not to have recognized that in this sense, the goals of less climate change andless petroleum dependence are at odds with each other. Thus if fuel-efficiency regulations are usedin lieu of price increases, it is important to also use complementary policies to prevent prices fromfalling and/or to promote technological innovation in alternative energy sources.
Of course, the effectiveness of such complementary policies is subject to limitations. One isthat that before investors will embark on major projects to find alternative ways of producing
energy, they need assurance that the motivating policies will remain in place for a long time.
Another is that high fuel prices for consumers create incentives for manufacturers only to the extent
that consumers respond to the fuel costs of travel. This latter concern is the subject of the next
subsection, where recent research is shown to suggest that this responsiveness is small and likely
declining.
2.4 The price elasticity of fuel demandThis section discusses our own recent work on estimations of the price elasticity of demand forgasoline. There is already a lot of research on this elasticity, but we think ours is particularly
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informative for the topic at hand, for several reasons. First, we measure not only the price elasticity
but two distinct responses that underlie it: changes in amount of driving and changes in fuelintensity. Second, the first of these distinct responses also tells us the magnitude of the “reboundeffect,” which is one potentially important by-product of fuel efficiency regulations. Third, weinvestigate how these underlying responses to fuel prices depend on factors like income, the degreeof urbanization, and fuel costs. We find that the responsiveness of driving to fuel costs declines withincome and urbanization, and increases with the initial level of fuel costs. Considering themagnitudes of these dependencies, by far the most likely outcome for the future is that this
responsiveness will decline further, a prediction that substantially affects how transport policies
should be designed.
Our work uses a 39-year cross-sectional time series of US states (plus District of Columbia)
covering years 1966-2004. This is a three-year extension of the data set used in Small and Van
Dender (2007a); otherwise, the methodology reported here is very similar to that paper.8
We decompose changes in fuel consumption into three parts: changes in travel per adult (M)for a given vehicle stock, changes in vehicle stock per adult (V), and changes in the average fuelintensity of vehicles (Fint). These changes are specified as three simultaneous equations, estimatedsimultaneously in logarithms.9 In this way we overcome one of the confusing aspects of the past
literature, which only rarely has accounted for the fact that fuel efficiency (the inverse of Fint) is
chosen jointly with travel and vehicle stock. (We envision although do not formally model adecision process in which consumers and motor-vehicle manufacturers interact in new-vehicle
markets while responding to constraints or incentives set by regulation.) We can then measure the“structural elasticity” of travel with respect to fuel cost per mile, ε Mˆ , PM , accounting for responses
both through fleet expansion and through utilization of a given size fleet.10 Empirically, we find that
ignoring the simultaneous determination of travel and fuel intensity would seriously overestimate
the magnitude of that elasticity.
Travel (M) is generally assumed by us and others to respond to fuel cost per mile PM rather
than responding separately to its separate components (fuel price and fuel intensity). For this reason,
the elasticity ε Mˆ , PM provides information about two different policies. It is part of the priceelasticity of gasoline (since gasoline price is one component of PM); at the same time it measures the
responsiveness of travel to changes in fuel efficiency (the other component of PM). In the latter
context, the responsiveness is often called the “rebound effect,” so called because it offsets a portionof the fuel savings that would result from an increase in fuel efficiency in the absence of any
behavioural response.11 Following convention, we define the positive quantity b ≡ −ε Mˆ , PM as therebound effect, and express it as a percentage. For example, if ε Mˆ ,PM =-0.20, the rebound effect issaid to be 20%.
Our empirical system also accounts for the slowness with which changes can occur, e.g.
because changes in the vehicle fleet require purchases and retirements of vehicles. In this way wedistinguish between short and long run responses. Technically, this is achieved by including lagged
values of the dependent variables. 12 In the travel equation, this is equivalent to assuming that there
is a desired level of travel and that any difference between this desired level and the level attained in
the previous year is diminished in one year by a fraction (1-αm), where αm is the coefficient of thelagged value of the variable. Thus the short-run response (that occurring in the same year) is smaller
than the long-run response. The long-run rebound effect is approximately: 13

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LONG-RUN TRENDS IN TRANSPORT DEMAND -

bL ≅

179

− ε Mˆ ,PM
bS
=
.
m
1− α
1− α mAs indicated, our main innovation over previous studies is to specify the equation determining
vehicle travel so that the “rebound effect” is not a constant, but rather varies with income, fuelprice, and urbanization. This is accomplished by specifying the equation for vma (the logarithm ofvehicle-miles travelled per adult) so that the logarithm of fuel cost per mile, pm, appears not only asa single variable (with coefficient βpm), but also interacted with other variables including itself. We
define three such variables: pm*inc, pm*pm≡pm2, and pm*Urban; we call their coefficients β1, β2,and β3. Then the structural elasticity in this equation, which is approximately the negative of therebound effect, consists of four terms:14

ε M ,PM =∂ (vma )= β pm + β 1 ⋅ inc + 2β 2 ⋅ pm + β 3 ⋅ Urban . (1)∂ ( pm)The results of estimating the model are quite similar to what we found for the slightly shortertime period used in Small and Van Dender (2007a). The most important coefficients are
summarized in Table 3.

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180 – LONG-RUN TRENDS IN TRANSPORT DEMAND
Table 3. Selected estimation results for the three-equation model, 1966-2004
Equation and variable

CoefficientsymbolCoefficient estimate

Standard error

Equation for vma:pm
-0.04070.0042pm
pm*inc0.06960.0132
1
pm*pm-0.0169
0.00642
pm*Urban
0.02550.01003inc
0.10440.0134m
Lagged vma
0.79800.0120Equation for fint:
pf+vma-0.0297
0.0064cafe-0.0882
0.0110f
Lagged fint
0.84500.0127
Notes to Table 3:vma = logarithm of vehicle-miles travelled per adultpm = logarithm of fuel cost per mile (normalized)
inc = logarithm of income per capita
Urban = fraction of population living in urban areas
fint = logarithm of fuel intensity, i.e. log (1/E) where E = fuel efficiency
pf = logarithm of fuel pricecafe = variable reflecting how far the CAFE standard is above the desired fuel efficiency based onother variables (Small and Van Dender 2007a, section 3.3.3)
pf+vma is log (price of fuel * vehicle-miles travelled), representing the logarithm of the incremental
annual fuel cost of a unit change in fuel intensity; thus it may be interpreted as the logarithm of
the “price” to the user, in terms of extra annual operating cost, of vehicle features that cause
higher fuel intensity.
For measuring the “rebound effect,” our primary interest is in the first four coefficients shownin Table 3. The short-run rebound effect for average conditions in this sample is approximately-β pm=0.0407, i.e. 4.07%, while the long-run rebound is 4.95 times this value, or 20.1%. The
coefficients for the three interacted variables involving pm (i.e. β1, β2, and β3) show that themagnitude of the rebound effect declines with increasing income and urbanization, and increases
with increasing fuel cost of driving. The net result is that the rebound effect declined substantiallyover time – which we confirmed by estimating the equation (without the three interaction terms)
separately for time periods 1966-1989 and 1990-2004, with the result that the rebound effect fell byhalf from the earlier time period to the later one.15
The coefficient of inc confirms the conventional expectation that vehicle-miles travelled rises
with rising income: the income-elasticity is approximately 0.1 in the short run and 0.5 in the longrun. The coefficient αm of lagged vma shows that the long-run effect of any variable on vehicle
miles travelled (VMT) is about 1/(1-αm)=4.95 times larger than the corresponding short-run effect.
This may seem surprising given our finding that changes in the size of the fleet play only a smallrole. However, changes in travel can occur either quickly, for example through carpooling or trip
chaining, or over a longer period, for example through changes in home and workplace locations oreven in land-use patterns.

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LONG-RUN TRENDS IN TRANSPORT DEMAND -181

Our equation system also measures the extent to which the fleet-average fuel efficiency isadjusted in response to fuel prices. The short-run elasticity is approximately the coefficient ofpf+vma in Table 3, or -0.03, implying a long-run elasticity of -0.15.16
We show in Table 4 various implied elasticities, computed at two different sets of values forthe explanatory variables inc, pm, and Urban. One set is the average values over our sample and theother is the average values over the last five years of the sample.17
Table 4. Estimated Elasticities
1966-2004

2000-2004

26,506
1.91

33,669
1.69

Average values (real 2006 $):Household income ($/year)
Fuel price ($/gal)
Calculated elasticities:
Vehicle-miles traveled
Fuel intensity
Fuel consumption

Short run-0.041-0.035-0.074

Long run-0.210-0.193-0.363

Short run-0.011-0.031-0.041Long run-0.057-0.191-0.237

Rebound effect (%)

4.1%

21.0%

1.1%

5.7%

Source: Small and Van Dender (2007c), estimating using full data set.
Elasticities are with respect to fuel cost per mile for Vehicle-miles traveled, and fuel pricefor other quantities.
Columns labeled "1966-2004" use average income and fuel cost for the entire sample
period.
Columns labeled "2000-2004" use average income and fuel cost for the last five years of
the sample period.
Standard errors are approximately as follows:(a) 1966-2004, short run: 0.004 for "Vehicle-miles traveled", 0.020 for "Fuel efficiency"and "Fuel consumption".
(b) 2000-2004, short run: 0.007 for "Vehicle-miles traveled", 0.020 for "Fuel efficiency"and "Fuel consumption".
(c) Long run: 5-6 times as large as for short run.

Under average conditions over our entire sample period, the measured rebound effect is 4.1%
short run and 21.0% long run. However, these values are found to fall dramatically when we
consider conditions that prevailed in 2000-2004: over those years the rebound effect on average isjust 1.1% short run and 5.7% long run.
Why should rising income diminish the rebound effect? Our model provides no direct answer,
but there are some plausible explanations. First, higher incomes cause the share of fuel expendituresin total expenditures to decline, which may lead to lower elasticities. Second, higher incomes leadto higher values of time, so that time costs of travel become relatively more important than fuelcosts. Higher fuel costs then translate into proportionally smaller increases in the generalized priceof travel (which is the sum of time and money costs), and assuming that drivers respond mainly tothis generalized price, this reduces the elasticity with respect to the money costs. However, there arereasons why higher incomes could lead instead to larger elasticities: the share of discretionary
driving is likely higher for higher income households, and it is easier to cut back on such driving
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182 – LONG-RUN TRENDS IN TRANSPORT DEMAND
than on “mandatory” travel. Hughes et al. (2006) find larger price elasticities of gasoline demandfor higher incomes than for lower income households, while at the same time finding that thiselasticity declines over time.18
The elasticity of fuel intensity, unlike that of travel, is found to be almost constant, eventhough we tried specifications that would allow it to vary. This elasticity is somewhat underresearched, with results varying widely depending largely on type of data set. Our results for its
absolute magnitude, namely short-run and long-run values of 0.031 and 0.191 over the recent
period, are quite similar to the estimates of 0.017 and 0.150 obtained by Li, Timmins and vonHaefen (2006), who more directly measure the responses of consumers in the form of modelspecific decisions about scrappage and new-vehicle purchases.
The long-run price elasticity of gasoline in our estimates is -0.363 over the entire sample,
declining modestly in magnitude to -0.237 over the last five years. With the travel component
declining sharply and the fuel-intensity component approximately constant, travel is becoming a
notably smaller component of the response to fuel prices. The finding that responses to fuel prices
take place through changes in fuel economy more than through changes in the amount of driving is
confirmed by a study for twelve OECD countries by Johansson and Schipper (1997), and more
recently in a meta-analysis (an econometric analysis of earlier estimates of the fuel price elasticityof the demand for fuel) by Brons et al. (2007).19
What about the future? In a nutshell, our results suggest that fuel consumption by passenger
vehicles has become more price-inelastic over time, and that it is increasingly dominated bychanges in fuel efficiency rather than in amount of driving. Furthermore, our results identify two
main reasons for this: rising incomes and falling real fuel prices. One of these – rising incomes –can be presumed to characterize the future as well, whereas the other – falling real fuel prices –probably cannot. So we need to consider the relative magnitudes of these two factors.
Real income in the US grew at 1.4% per year over the period 1984–2004 (US Bureau of Labor
Statistics 2007). As for gasoline prices, the US Energy Information Agency (EIA) projects in its“reference case” that they will be roughly constant in real terms after declining slightly from a spikein 2005-2006.20 The EIA also considers low- and high-price cases; in the latter, real prices rise on
average by 1.4% per year. In the high-price scenario, then, rising incomes are causing the reboundeffect to diminish by 0.097 percentage points per year, while rising fuel prices are causing it to riseby 0.047 percentage points per year.21 Thus even in a scenario projecting high growth of fuel prices,
the influence of income growth dominates; it would do so even more if we used the 2.3%/year
income growth projections from US EIA (2007) over the period 2005-2030. Thus we should expect
the rebound effect and the price-elasticity of fuel consumption both to continue to become smaller.22
2.5 Summary
The demand for oil as a source of energy is likely to grow along with income, especiallyoutside the OECD. With an upward sloping supply curve, this results in higher prices. In addition,
the share of the transport sector in total oil demand will likely increase: this reduces the overall
elasticity of oil demand, given that transport has very limited access to alternative technologies inthe short term. Moreover, the elasticity of fuel demand in transport declines as incomes increase, apattern which we identified for the US and which we expect applies elsewhere also. This further
reduces the price elasticity of oil demand. The declining elasticity implies that short-run supply
shocks have bigger price effects and that long-run demand will not be curbed strongly as prices rise.

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LONG-RUN TRENDS IN TRANSPORT DEMAND -183

A common policy response to (real or perceived) excessive costs of reliance on oil is tomandate fuel-economy improvements in the transport sector. Such policies may well be justified,
especially when households are thought to under-invest in fuel economy, and when higher fueltaxes are difficult to implement. It is not straightforward, however, that regulation of fuel economy
in itself contributes to the mitigation of climate change. The reason is that better fuel economy alters
the rate of emissions, but not necessarily their time-aggregated total. This suggests that, if strong
reductions in CO2 emissions are desired, fuel economy regulation needs to be complemented byother policies such as a carbon tax.23
We have in this section focussed on the connection between energy and transport. In the next
section, we put the discussion in the broader framework of transport policy.

3. ENERGY POLICY IN TRANSPORT

We now turn to factors that shape the relative advantages of various transport policies toward
energy and other goals. We attempt to create a uniform framework by considering the marginalexternal costs of fuel-related and other transport externalities.
Long before energy issues rose to their present degree of prominence, transport was animportant and often problematic sector in the economies of nations and cities. The many problems
identified with the transport sector include large and irreversible investments, financial mechanisms,
subsidies, implications for regional economic growth and inter-regional integration, congestion,
safety, and negative spillovers to non-users through air pollution, noise, aesthetics, wildlife
disruption, water quality, availability of open space, and other mechanisms. These problems haveelicited numerous policy responses, some of which increase and some of which lessen the amountof transport undertaken. Furthermore, these policies are often thought to have far-reaching
implications for local, regional, and national economies, and they certainly involve strong impacts
on government budgets.
One must consider, then, the interaction of energy objectives with the objectives of these otherpolicies. Will attention to energy make other goals easier or harder to achieve? Do these other goals
alter in significant ways the optimal response to energy problems? Even aside from other goals,
how much of a role should transport policy play in achieving energy objectives? And just how big isenergy when viewed as a part of the overall policy environment for the transport sector?
One way to tackle these issues is by asking what responses would markets bring about in an
ideal world where prices could be brought into perfect alignment with marginal social costs – i.e.
with the extra costs incurred by all members of society, including the decision maker, due toparticular economic decisions.24 This involves looking at each as a market failure, and asking what
would happen if that failure could be eliminated within the market system. For example, if we knew
the costs global climate change, of macroeconomic disruptions due to reliance on unstable ormonopolistic energy suppliers, and of consumers’ myopia or lack of information enabling them tooptimally trade off energy efficiency against purchase price, and if we could trace these costs tospecific economic decisions, then we would know how much prices would have to change in order
to confront each decision-maker with the marginal social costs of those consumption decisions. We
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184 – LONG-RUN TRENDS IN TRANSPORT DEMAND
could then ask how decision-makers would react to such changes in price signals. How much would
they curtail transport energy use, and through what mechanisms? Such an analysis provides a guideas to what changes would be the most efficient ones to target, using public policy, if in fact it is not
feasible to bring about the theoretically desirable price signals.
The same type of analysis can be done for other transport problems, and has in fact been donein considerable detail for two of the most important – congestion and air pollution – and in a more
sketchy fashion for others including noise and safety. Once again, this produces a set of
hypothetical responses that thereby become appropriate candidate targets for public policy.
By comparing the resulting behavioural responses across the problems targeted, we obtain
answers to the questions asked above. In some cases, behavioural responses to remedy one problem
would exacerbate another; in other cases, the responses may work together, “killing two birds with
one stone”. Furthermore, by considering the relative magnitudes of the price signals involved, one
can quantify the judgment involved in the last question posed: how big are these problems relative
to each other?
A comprehensive analysis of this type would consume a work the size of an encyclopaedia.
We provide here a first cut, by considering two questions. First, what are the relative sizes of themarginal external costs of various transport problems, when averaged over a large class of users?
(Marginal external cost means that part of the marginal social cost not incurred by the decision
maker.) Second, how dramatically do those costs vary across user groups or local situations? And ifthey do vary, do the responses that would be undertaken in response to internalizing those costs also
vary? If so, then there is a strong case for looking at closely targeted policies that can bring aboutsuch diverse responses; if not, then a blunt instrument that changes average behaviour may beadequate. Local air pollution, and to a stronger extent congestion, are examples of externalities
where blunt approaches are not usually considered to be effective because what is needed is a set ofchanges in very specific situations like driving in big cities during peak periods, or driving a vehicle
whose emission control mechanisms are not working.
Table 5 collects estimates of marginal external cost due to several types of transport problems.
They are classified according to whether they vary mainly in proportion to fuel consumption, whichis the case for climate change and oil dependency, or in proportion to vehicle-miles travelled. For
comparison, the former are converted to a marginal cost per vehicle-mile, using the fleet average
fuel efficiency for passenger vehicles (e.g. 22.9 mi/gal for the US in 2005). Note however that interms of the thought experiment described above, the best policy responses to fuel-related andmileage-related externalities are quite different. Raising the price of fuel induces not only a mileage
reduction but a substantial increase in fuel efficiency, the latter increasingly dominating as
described in the previous section. As emphasized by Ian Parry and Small (2005), this differencedramatically affects the (second-best) optimal use of a fuel tax to address mileage-related
externalities: using their numbers, the tax rate would be set at only roughly 40 percent of the valuethat would be calculated by multiplying the cost/mile figures by fuel efficiency. Conversely, using a
distance-related tax (sometimes called a VMT tax) to address a fuel-related externality such as
global warming would fail to elicit one of the most important responses needed, which is anincrease in fuel efficiency of vehicles.

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LONG-RUN TRENDS IN TRANSPORT DEMAND -185

Table 5. Marginal external costs from automobiles, US cents/mile, 2005 prices
HarringtonMcConnell(US & Europe)
Low
High

Sansom et al.
(UK)
Low

Parry etal. (US)High fuelrelateda
(US)

High

a

Fuel-related:
Climate change
Oil dependency
Driving-related:
Congestion
Air pollution
Noise, Water
Accidents
Total
Percent fuel-related

0.3
1.6

1.2
2.7

0.5
n.a.

2.0
n.a.

0.3
0.6

3.7
2.4

4.2
1.1
0.2
1.1
6.6
22

15.8
14.8
9.5
10.5
50.6
7

31.0
1.1
0.1
2.6
35.3
1

35.7
5.4
2.5
4.5
50.1
4

5.0
2.0
n.a.
3.0
10.9
8

5.0
2.0
n.a.
3.0
16.1
38

Sources: Harrington and McConnell (2003), Table 3; Sansom et al. (2001); Ian Parry, Walls andHarrington (2007), Table 2. “High Fuel-related”.: same as Parry et al. except for climatechange ($0.76/gal, from Stern 2005) and oil dependency ($0.55/gal, from the high end of range in
Lieby (2007), Table 1.
Notes: All numbers converted to 2005 US price levels. n.a. means not estimated, in some cases due to an
explicit argument that the quantity is small. Fuel-related costs are converted from per gallon to permile using prevailing average fuel efficiency.

The fuel-related costs portrayed in Table 5 are potentially very large in aggregate. Taking the“high” values of the last column, and multiplying by just the 2.99 trillion vehicle-miles travelled in
the US in 2005, they come to $111 billion for global warming and $72 billion for oil dependency
annually.
Yet it appears that other, more prosaic, transport problems are even larger. The three studies
listed in Table 5 (excluding the last column) are unanimous in finding that congestion involves
larger external costs than fuel-related externalities, and except for the “low” Harrington-McConnell
values, the same is true of air pollution and accidents. In nearly all cases, congestion alone is foundto outweigh the fuel-related externalities by a large margin. These findings may seem surprising
until one realizes that congestion and air pollution have tangible and serious effects on most urban
residents on a daily basis. Congestion consumes huge amounts of time, and air pollution produces
demonstrable mortality. Climate change and oil dependency, by contrast, have effects that, as best
as can be determined from the admittedly imperfect modelling available, are in the distant future,capable of substantial amelioration by other means, and/or simply not very large when spread overthe enormous number of vehicle-miles producing the estimated aggregate impacts.
What about variation? The figures in Table 5 are national averages, but some of these costs
vary strongly over time and place. For example, a recent French study, discussed in Grange (2007),
finds that the marginal external congestion costs of driving in urban traffic are about ten times ashigh as those of driving in interurban traffic. This conclusion is corroborated by other studies, whichin addition point out that the congestion costs depend strongly on time of day (e.g. Proost et al.,2002). This is a second reason why fuel taxes are not well suited to deal with congestion. There isstrong evidence that the response to imposing targeted congestion charges (i.e. ones that vary bytime and place) would involve a lot of shifting of trips across time periods, modes, and routes, andOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 - © OECD/ITF, 2008

186 – LONG-RUN TRENDS IN TRANSPORT DEMAND
much less overall reduction of trips; thus the most efficient policies would aim at shifting trips inthis manner rather than simply reducing all trips.
Similarly, pollution costs from motor vehicle-use vary widely depending on location, fuel type,age of vehicle, and vehicle maintenance practices. for example, pollution costs are higher for diesel
than gasoline cars, because of the high health costs associated with emissions of small particulates.
This casts some doubt on whether the European “dieselization” strategy to increase fuel economy isopportune, as it increases emissions of particulates unless particulate filters become universal. The
US may embark on a “hybridization” strategy, which avoids the particulates issue but which also
involves expensive technology. More generally, given the high costs of further improvements ofemission abatement technology, one may question the desirability of this policy approach, as
policies to reduce emissions from small numbers of gross polluters become more attractive (Small,1997).
If we use the higher fuel-related figures in the last column of the table, the picture changes
somewhat – although even then fuel-related externalities do not dominate other externalities.
However, we think these higher figures are not well supported by existing evidence. In order tosupport this claim, we now consider more carefully the sources of the estimates shown for fuelrelated externalities, first for climate change (section 3.1) and then for oil dependency (section 3.2).
3.1

Marginal external costs of motor-fuel consumption due to climate change

The climate-change cost calculated by Parry et al. (2007), shown in the next to last column of
the table, is based on a damage estimate of US$25 per tonne carbon, i.e. $25/tC, at 2005 prices.25
This figure is consistent with results from a number of reviews including Cline (1990), Nordhaus(1994), ECMT (1998, p. 70), and Tol et al. (2000).26 More recent reviews include Tol (2005), who
reaffirms the validity of relatively low costs,27 and Stern (2006, pp. 287-288), who argues for muchhigher costs as discussed below.
Quantifying such costs is of course highly speculative, due especially to three features ofclimate change. The first is the highly uncertain effect of emissions on specific climate outcomes; it
is usually handled by acknowledging the uncertainty and stating results in terms of a specificassumed climate outcome, most often based on reports of the Intergovernmental Panel on Climate
Change (IPCC).
The other two features, however, give rise to two sources of major differences among analysts.
One is the unknown form of human adaptation to problems building up over decades and centuries.
The other is differences of opinion about the appropriate analytical procedure for aggregating
effects occurring over long time intervals. We consider each of these sources of controversy in turn.
Human adaptation to climate changes may occur in many ways, including changes in crops(e.g. Mendelsohn et al., 1994), public health measures, new water storage facilities, coastline
protection measures, and human migrations. Tol (2005) and a working group of the IPCC (Martin
Parry et al. 2007) provide thorough discussions. Such adaptive measures are expected to greatly
reduce the damage that would otherwise occur. To take one example, the European Commission(2007, p. 10) estimates that European damages from a 56 cm rise in sea level in the 2080s would beapproximately €€ 18 billion per year without adaptation but €€ 3 billion with adaptive measures.
Similarly, the relevant IPCC working group notes that “adaptation costs for vulnerable coasts aremuch less than the costs of inaction” (Parry et al. 2007, p. 40). Some adaptive measures will be
extremely costly, but these costs will be spread over many decades. Some, like migrations, may turnout to exact a terrible human toll, just as do natural catastrophes and various failures of
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governmental policies today. And adaptive measures cannot mitigate all damage: species
extinctions, flooding, damage to deteriorating aquatic environments, fresh water shortages, andmany other adverse effects are very likely to occur despite adaptation. Of course, such adverse
events are already occurring today, primarily for other reasons; so the relevant questions become
quantitative ones of how much and at what cost.
Measurement of the ultimate costs is full of hazards, but real progress has been made,especially with respect to converting damages to monetary costs. The evidence so far does notindicate that such costs dominate the more prosaic costs of congestion and air pollution that wehave become accustomed to in the field of transport. An analogy with a different transport problem
may be useful. The collapse of a well-used bridge in Minneapolis in August 2007 elicitedexpressions of great urgency for dealing with the problem of US infrastructure deterioration. Yet theresulting 13 deaths are far less than just one day’s average fatalities from US motor-vehicle
accidents (116 in 2004). So which is the larger national problem: infrastructure deterioration or
routine safety? It is this kind of question that is implicitly addressed by cost figures like those in
Table 5. To the extent they are valid, the appropriate conclusion is not to ignore the problems withsmaller costs; it is rather to maintain perspective relative to other problems, even prosaic ones, whensetting priorities.
The second major source of differences among analysts is the matter of “discounting” future
costs in order to aggregate them into a number applicable to an emission produced at a specified
time (e.g. today). This is a technical debate, largely over the ethical meaning and economic
interpretation of parameters that characterize modern models of economic growth. In what
Weitzman (2007) calls the “majority view” of most economists, distant economic consequences
should be discounted at interest rates on the order of 4%–6%. This view relies in large part on thefact that observed savings behaviour appears to be roughly consistent with a long-term growthmodel in which people discount their own or their descendants’ future utility at very modest interest
rates (the so-called “pure rate of time preference”), and simultaneously seek to smooth theirconsumption in a world where long-term growth is making them richer. The consumption
smoothing part of this justification can be stated equivalently as an ethical position against income
inequality across generations. In this interpretation, since future generations are likely to be richer
than us, we would discount the advantage to them resulting from any sacrifice by us. Yet anotherjustification is that the world economy is capable of generating returns on investments of at least
4%–6%, and these returns may be used to mitigate or compensate for the adverse futureconsequences of climate change.
There is actually little disagreement among economic analysts about the principles just stated.
The disagreement comes in the form of numerical parameters. The “majority view” infers fromsavings behaviour that people apply a pure rate of time preference of 1–3% per year, both forthemselves and for descendants to whom they bequeath wealth. Others, however, argue that for
purposes of policy any such preferences must be overridden by an ethical principle that future
generations are just as important as current ones. Most prominently, the Stern Review issued by the
UK Treasury (Stern 2006) argues that the only legitimate basis for a pure rate of time preference is
uncertainty over whether those future generations will actually be alive, resulting in use of a purerate of time preference of just 0.1%. As for the aversion to income inequality, Stern uses a
parameter that implies indifference between a given percentage loss in world output at any point in
time; whereas the “majority view” is for a greater aversion to income inequality so that one would
not accept a 1% cut in living standards today in order to achieve a 1% increase at some time whenpeople are ten times richer. The implication of Stern’s assumptions is an actual discount rate of only
1.4% per year (Weitzman 2007).
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Nordhaus (2007) argues that these two parameter assumptions used by Stern, taken together,
are inconsistent with people’s observed behaviour, in particular implying they would choose to savemuch more than they do. (See however the rebuttal to this type of argument in Stern, 2006, pp. 4748.) More transparently, Nordhaus provides some numerical examples of the implications of using
Stern’s 1.4% social discount rate. Suppose a “wrinkle in the climatic system” threatens to reduceworld consumption by 0.1% forever, starting in year 2200. It could be averted by sacrificing 56% of
one year’s world consumption today. Stern’s methodology produces the result that we should
undertake that expense; the low interest rate for discounting turns the climate wrinkle, which might
never even be noticed, into a catastrophe in present value terms.
It is worth noting that the Stern Review itself, despite its language of catastrophe, does notproject world per capita consumption to decline in real terms, even with uncontrolled climatechange. Rather, in the worst of all the cases calculated, it is projected to grow to 8.6 times today’slevel by year 2200, instead of to 13.2 times as it would in the absence of climate change.28 Yet
because this reduced income continues forever, and is discounted at only 1.4% per year, it has apresent value equivalent to reducing per capita consumption by 14.4% every year from now to
forever (Stern 2006, Table 6.1). Thus Stern would evidently recommend that we cut worldconsumption if necessary by 14%, starting today and lasting forever, in order to prevent ourdescendants from having to live with a lower income growth than they otherwise would enjoy.
Would we really accept such a bargain? These examples illustrate the hazards to common sense that
accompany arguments about long time periods with very low discount rates.
Weitzman (2007) provides an insightful discussion of a possible alternative rationale for theparameter values used by Stern. In Weitzman’s view, the most important issue is uncertainty about
the prospects and consequences of unlikely but extremely damaging results of climate change –events such as collapse of a continental ice sheet or reversal of a major ocean current. Neither Sternnor his critics have a way to model this type of uncertainty rigorously. Weitzman posits that becauseof this, Stern may have “tweaked” his parameter values intuitively to reflect it. The trouble is thatsuch uncertainty takes us into possibilities that we know little about and cannot model well.
Weitzman’s own conclusion is that the “majority view” provides a good starting point for
immediate policy, but that the uncertainty justifies a crash program of research and policy debate
aimed at learning about the potential adaptations to and ultimate consequences of small-probability
catastrophes. Weitzman also shows, using several examples, that the response called for may well
be closer to that coming out of Stern’s model than that from the majority view.
This technical discussion may seem to disconnect from the main thrust of Stern’s and manyother people’s analyses of climate change. These writings are filled with descriptions not of happy
people enjoying living standards ten times greater than today’s, but rather of terrible disruptions totheir well-being. Yet the technical analysis just described is the one that underlies Stern’s damage
figure of US$96 per tonne CO2 (at 2005 prices), equivalent to $352/tC or $0.85/gal for gasoline.29
Part of Weitzman’s critique is that Stern may have adapted the parameters of a highly technical and,perhaps, ultimately unsatisfactory analysis using conventional growth theory in order to capture thepossibilities, even if remote, that the world will turn out much worse than the scenarios being
modelled. Unfortunately, there does not at present seem to be an adequate basis for analysis of suchcontingencies within a decision-theoretic framework.
3.2 Marginal external costs of motor-fuel consumption due to oil dependency
Some sophisticated analysis has gone into measuring a marginal social cost for fuelconsumption due to oil dependency. One of the most thorough and recent is Leiby (2007). Ian ParryOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 - © OECD/ITF, 2008

LONG-RUN TRENDS IN TRANSPORT DEMAND -189

and Darmstadter (2003) provide a useful review, citing studies producing estimates of from zero to
US$0.33/gal; their own preference is $0.125/gal. (See also Davis and Diegel 2007, table 1.8.) Leiby(2007, Table 1) obtains a range by considering likely parameter values within a single model: when
divided by 42 gal/bbl, his range is $0.16–$0.55 per gallon, with a preferred value of $0.32. We
include the value $0.55/gal in our “High fuel-related” column of Table 5.
However, we have severe reservations about accepting these numbers as indicators of themarginal value of reducing oil imports. The costs of oil dependency are essentially the total cost to anational or regional economy (specifically that of the US) of various features of the world oil
market that cause problems to a nation relying heavily on oil imports. Specifically, the featuresconsidered by these authors are a “monopsony premium” and the costs of macroeconomic
disruptions. The first is rightly described Leiby as a foregone opportunity: because the US is a largepart of the world oil market (on the buying side), it could, by exerting coordinated national policy,
reduce our import demand as seen by the Organization of the Petroleum Exporting Countries(OPEC) and thereby reduce OPEC’s monopoly power. But the lion’s share of the monopsonypremium consists of curtailing the transfer of wealth abroad to OPEC nations, not a saving of world
resources. Indeed, the analysis takes as given that the inefficiency of OPEC’s monopoly power is by
reducing world consumption below efficient levels; so it is unclear that further reducing worldconsumption would create worldwide benefits. Rather, it is mainly an attempt to reduce a transfer
occurring through the workings of world trade. It seems to us inconsistent to use a worldwide
perspective in valuing climate-change costs while adopting a parochial perspective in valuing oil
dependency costs.
This leaves costs of macroeconomic disruption. There is evidence that normal pricefluctuations in world oil markets are magnified by the distortion of monopoly power, and that
resulting fluctuations in oil prices tend to cause macroeconomic instability, in particular recessions
following oil-price increases. These recessions carry an economic cost that can be regarded as anexternal cost to the consumption decisions of individual economic decision-makers. We do not
disagree with this analysis, although it must be qualified by recognizing that both of these pathways
are subject to institutional factors which may change – in particular, national banks are becoming
more “savvy” about counteracting oil-price shocks. But as with OPEC monopoly power, theobvious implication is that market prices are too high, not too low. Thus macroeconomic disruption
is not an argument for raising the price facing decision-makers, in the usual manner of an unpriced
external cost. Rather, as acknowledged by Leiby, it is an argument for other policies that reduce theextent of price fluctuations or their adverse impacts on macroeconomic performance.
Thus both components of the oil-dependency costs, as measured by current studies, may beseen as indicators of the potential value to the economy of a large nation or region of reducing the
proportion of its supply consisting of imports from monopolized and/or unstable sources. It is lessclear how exactly reducing transport use of conventional oil fuels brings about this desired result.
Curtailing demand, for example by fuel-efficiency standards or incentives to reduce motor-vehicle
travel, would come partly from domestic sources (which are currently producing some oil at very
high marginal cost due to high world prices). Thus such reductions cannot be taken one for one as
reductions in imports, and in fact it’s unclear whether they would even change the fraction of US
consumption represented by imports. Thus while oil dependency may well be a problem thatwarrants action, the relevant factors are more country-specific and the relevant policies more
specific to trade and macroeconomic conditions than the other problems discussed here.
Furthermore, simply raising the price is not obviously a solution, since many of the drawbacks ofoil dependency result from the price being artificially high.

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To summarize, oil dependency is an argument for interventions to reduce the market power ofoil producers by promoting conservation or substitutes for oil. It has significance for transport
policy, but it does not provide an argument for fuel taxes or for other interventions that would raisethe domestic price. On the contrary, oil dependency and climate change have offsetting effects on
world oil consumption, the first reducing it and the second increasing it relative to a social
optimum. To put it differently, if one takes climate change as the truly overriding policy problem,
then one must welcome the possibility that world oil markets are organized in such a way as to keep
current oil consumption artificially low.
3.3 Implications of analysis of marginal external costs
We believe that damage estimates of the orders of magnitude shown in Table 5, excluding theright-most column, are the best guides to transport policy within the limitations of quantifiable
uncertainty. Several unpriced external costs of motor vehicle travel appear to have larger
measurable external costs – when traced specifically to motor vehicle use – than those of climatechange and oil dependency.
This finding does not imply that control measures are unwarranted. On the contrary, whentotalled over the trillions of vehicle-miles currently being driven throughout the world, these costs
are large and warrant significant policy interventions. It is less clear that they are amenable toamelioration through transport policy. Furthermore, even from a broader policy perspective, there
are tradeoffs. Reducing greenhouse gases and energy insecurity are important and valuable
activities, but so are other uses of our resources. For example, IPPC (2007) notes that the ability ofpoorer nations to cope with the climate change that is already certain to occur is greatly affected bytheir development path; so one must weigh greenhouse gas control against development needs incircumstances where they compete for funds or attention.
More specifically for transport, we reach two conclusions. First, one must pay attention to theside effects of control measures on such prosaic but real costs as air pollution, traffic accidents, andabove all congestion. The idea that climate change is so overwhelmingly catastrophic that it trumps
all other environmental or transport policies – an idea expressed or implied by some recent writings– is wrong and quite dangerous.
Second, an ideal approach to controlling energy use is not likely to reduce motor vehicle travel
very much. We know from our study of demand elasticities that users would curtail travel only
slightly if faced with its fuel-related external costs. Furthermore, it seems likely that abatement
costs are higher in transport than in some other sectors (e.g. Knockaert and Proost, 2005), whichsuggests that it is more effective to focus abatement efforts elsewhere. An ideal approach willaccomplish most of its results through technological changes specifically targeted to energy savings,
mostly through the use of more fuel-efficient vehicles and perhaps also through alternative fuels. By
choosing technological solutions when permitted, consumers will avoid more thoroughgoing
behavioural changes such as changes in travel mode, trip patterns, and home and work location,
which evidently are more costly for them.
Combining the marginal-cost analysis with our review of fuel-consumption elasticities, itappears that transport is not the ideal sector to target for solutions to energy problems. It surely canand should play a role, but not the dominant one that some assume. Where, then, might we find abetter avenue for energy policy? Many analysts have identified electricity production from fossil
fuels as a promising one because it entails more economical opportunities for fuel switching orconservation. To review the electricity sector would take us outside our scope, but we can cite one
statistic that helps make the point. Ian Parry (2005) discusses the implications of the “majority
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LONG-RUN TRENDS IN TRANSPORT DEMAND -191view” of the external cost of carbon emissions, taking it to be $30/tC. Applying an externality tax ofthis magnitude would raise the price of gasoline by $0.07 per gallon, not enough to have mucheffect on motor-vehicle fuel consumption. But applying such a carbon charge to coal would morethan double coal prices!30 This would have significant effects on producer, and maybe evenconsumer, decisions about electricity production and use. It would of course also affect otherindustrial uses of coal, which are increasing at a frightening rate in fast-growing economies like thatof China.

4. CONCLUSION

Our analysis suggests that transport is relatively unresponsive to broad-based price signals, inparticular to changes in prices of fuels. The main exception to this is that there is considerable scope
to improve the fuel efficiency of vehicle fleets, mainly through technological changes but also tosome extent through consumer choices among vehicle sizes and types. As a result, we should not
expect to see dramatic changes in modal shares or in the nature of transport systems. Furthermore,this unresponsiveness suggests that it is costly to reduce energy use in transport, relative to othereconomic activities, and thus that efficient policies will probably not extract as much energy savings(in percentage terms) from transport as from other sectors.
A perennial policy issue is whether to address problems with price incentives (in this case,higher prices) or with regulatory measures. Our review suggests that either approach can work.
Using prices has the disadvantage that quite large price increases are needed to obtain much
response, and this may be beyond the political capacity of most countries. Fuel efficiency
regulations are a relatively quick way to reduce oil imports where energy security is a concern, andthe danger of inducing more travel as a side effect is probably minor. But if reducing climatechange is a primary goal, we think it is important to supplement any regulations with either
technology policies or some price-oriented policies because otherwise the stock of fossil fuelsremains available and attractive for future use, making it that much harder to move toward a global
path of lower carbon-dioxide emissions.
Broad-based carbon taxes remain an excellent tool for climate control. Their impacts ontransport would be modest, mainly in the form of promoting technological improvements andvehicle-mix shifts that increase fuel efficiency. This is at it should be, because it reflects relatively
high costs of reducing oil use in transport. There are other sectors, especially those that burn coal,that make better targets for energy policy.
Our review of marginal external costs suggests that energy policy could be the “tail wagging
the dog” in transport. Other transport problems, notably congestion, local air pollution, andaccidents, are associated with considerably higher marginal external costs than are climate change
and energy security. It follows that policies to deal directly with these other problems deserve highpriority, regardless of energy policies.

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NOTES

1.

Figures taken from CEC (2007, p. 26) and converted to 2005 prices using the US Consumer
Price Index (CPI).

2.

Crude oil accounted for 90.6% of all petroleum used in 2005 (TEDB, Tables 1.2 and 1.3).

3.

See Davis and Diegel (2007), Tables 1.13 and 2.1 for the figures quoted in this paragraph.

4.

CAFE regulations were much stricter for cars, which probably induced manufacturers to
produce light trucks as substitutes. We suspect furthermore that the prevalence of light trucks
in the vehicle fleet became self-reinforcing by inducing changes in consumer preferences, due
to a fad effect and/or an “arms race” as each driver seeks to avoid colliding with vehicles muchlarger than his or her own.

5.

Various explanations of why households under-invest in fuel economy have been put forward,
for example “consumer myopia” (possibly because private discount rates exceed social ones)
and loss aversion (consumers undervalue future fuel savings because they are unsure about
them and risk averse). See Greene and German (2007). There also is evidence that consumers
do not accurately calculate benefits from fuel economy (e.g. Turrentine and Kurani, 2007), but
this does not imply systematic errors in the direction of underinvestment.

6.

The source for these figures is Davis and Diegel (2007), Tables 8.2, 7.3, and 3.4.

7.

US FHWA (2007). These preliminary data are extrapolated from a fairly small number oftraffic counting locations, and are less reliable than the final estimates (derived from the
Highway Performance Monitoring System) published for earlier periods.

8.

See Small and Van Dender (2007a,b) for further methodological details.

9.

The equations are estimated using three-stage least squares. In order to account for fixedfactors affecting a given state, we use a “fixed effects” specification which estimates a separate
constant term in each equation for each state.

10. This structural elasticity comes from the first two of our equations, explaining travel andvehicle fleet size. Small and Van Dender (2007a) show that it can be written in terms of theelasticities measured within these two equations:
ε Mˆ ,PM =ε M ,PM + ε M ,V εV , PM
1 − ε M ,V εV ,M

where εM,PM denotes the elasticity of travel with respect to fuel cost per mile in the travel
equation; εM,V denotes the elasticity of travel with respect to vehicle fleet in that same
equation; and where εV,M and εV,PM denote the elasticities of vehicle fleet size with respect
to amount of travel and to cost per mile, both within the second equation. Cost per mile ofOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 - © OECD/ITF, 2008

LONG-RUN TRENDS IN TRANSPORT DEMAND -193

travel, PM, is defined as the price of fuel times fuel intensity. Thus ε Mˆ , PM depicts the result ofa hypothetical exogenous change in PM (or of an endogenous change in PM caused by anexogenous change in regulations affecting fuel intensity); yet the actual estimation of thesecomponent elasticities accounts for the simultaneous determination of vehicle stock, vehicle
usage, and fuel intensity within the estimation sample. Empirically, we find that εM,V is verysmall, so that ε Mˆ , PM differs little from ε M ,PM .
11. A distinction can be made between direct and economy-wide rebound effects. Our estimate
concerns the direct effect, as it is limited to the effect of increased fuel economy on travel
while holding constant all other factors except vehicle stock. But wider economic effects
clearly exist that affect energy consumption: for example, consumers will spend some of their
saved energy expenditures on other goods that also consume energy. Empirical evidence onsuch indirect effects is relatively scarce. According to one review, computable generalequilibrium models generate values of the economy-wide rebound effect of around 50%,
whereas a UK macro-econometric model generates a value of 7% (Sorrell 2007, p.58).
12. Another dynamic effect we account for is autocorrelation among the error terms in eachequation; however, our specification is comprehensive enough that autocorrelation, which isindicative of important omitted variables, is quite small. In previous research, using shortertime periods, it has been difficult to distinguish between autocorrelation and lagged dependent
variables, which is important to do in order to distinguish short- and long-run responses.
13. A more precise relationship accounts for the fact that in the three-equation system, the lagged
values in more than one equation can affect the long-run response; specifically:bL =− ε M ,PM ⋅ (1 − α v ) − α mv β 2v
(1 − α m )(1 − α v ) − α mvα vm

where αv is the coefficient of the lagged dependent variable in the equation explaining vehicle
stock, αmv is the coefficient of vehicle stock in the equation explaining travel, αvm is thecoefficient of travel in explaining vehicle stock, and β 2v is the coefficient of pm (the logarithmof cost per mile) in the equation explaining vehicle stock. All the dependent variables are
expressed in logarithms. See Small and Van Dender (2007a), equation (7).
14. The factor 2 in this equation is a consequence of properties of the derivative of the quadratic
function (pm)2.
15. More precisely, the short-run rebound fell from 4.8% to 2.9%, while the long run rebound fell
from 21.1% to 7.7%. These declines are not in the same proportion because the estimatedcoefficient of the lagged dependent variable also changed between time periods.
16. The precise equations for the short-run and long-run elasticities of fuel efficiency with respect
to fuel price, again accounting for feedbacks across all three equations, are shown as equation(9) in Small and Van Dender (2007a).
17. The third elasticity shown is the price elasticity of gasoline consumption, calculated as follows:
ε F ,PF = ε Mˆ ,PM ⋅ (1 + ε I~ ,PF ) + ε I~ ,PF , where ε Mˆ ,PM and ε I~ ,PF are the elasticities reported in theprevious two rows of the table. This equation is derived by USDOE (1996, p. 5-11) and SmallOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-821-0121-6 - © OECD/ITF, 2008

194 – LONG-RUN TRENDS IN TRANSPORT DEMAND

and Van Dender (2005, eqn. 6); the term (1 + ε I~ ,PF ) was inadvertently omitted in Small and
Van Dender (2007a) when calculating elasticities of gasoline consumption, causing thoseelasticities to be slightly overstated – see Small and Van Dender (2007b) for the correct values
for the shorter (1966-2001) data set used in those papers.
18. Yet another factor is that richer households own more vehicles, allowing them to respond tofuel price increases by using the more fuel-efficient vehicles more intensively. This seems
mainly a short-run reaction, and would tend to make them respond less through changes intravel but more through changes in average realized fuel efficiency. Basso and Oum (2007)
discuss conflicting evidence from cross-sectional studies on the relationship between income
and the price elasticity. Most recently, Wadud et al. (2007a,b) find, as we do, that the priceelasticity is smaller at higher incomes.
19. The meta-analysis does not investigate whether the price-elasticity of fuel consumption
depends on income. However it does test whether it depends on a pure time trend, after allother measured determinants are controlled for, finding no evidence of such dependence. This
result is consistent with our model, which also finds no significant time trend in the reboundeffect, even when the three interaction terms in the estimating equation are removed. Weinterpret this to indicate that a simple time trend is inadequate to capture the effects of thecomplex changes in income, urbanization, and fuel cost over the time periods covered by thevarious studies.
20. See US EIA (2007), “Year-by-Year Reference Case Tables (2004-2030),” Table 3, for average
price of motor gasoline. Prices are projected to decline slightly in real (inflation-adjusted)
terms, by an average of 0.2% per year, over the period 2005-2030.
21. These numbers are calculated from the figures in Table 3, using equation (1), as
0.0696*0.014*100 and 2*0.0169*0.014*100, respectively.
22. At some point our equations predict that the rebound effect would become zero and thennegative; obviously this is contrary to theory and must be regarded as a limitation of
extrapolating our equations beyond the primary range of the data set on which they are
estimated.
23. If economy-wide rebound effects are large, which is uncertain but possible (cf. footnote 8), thisis an additional reason for combining fuel economy regulations with fuel or carbon taxes.
24. This is a simplification, as the presence of market failures and policy concerns outside thetransport sector implies that optimal transport prices likely deviate from marginal social costs;
in the jargon, we are in “second-best”. The exact nature of such deviations is difficult todetermine, but recent research suggests that the deviations may be smaller in the transport
sector than in other sectors, because price changes in transport do not strongly exacerbate other
inefficiencies in the economy, notably those related to labor taxes (West and Williams, 2007).
At any rate, it is very likely that second-best transport pricing would align charges moreclosely with external costs than is the case for the current price structure, so that thecomparison discussed in the text is a useful one.
25

One tC means one metric ton or tonne (1000 kg) of carbon. Given that carbon comprises afraction 12/44=0.27 of the weight of a carbon dioxide molecule, $1 per tC is equivalent to
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LONG-RUN TRENDS IN TRANSPORT DEMAND -195$3.67 per metric ton of CO2. According to National Research Council (2002, p. 85), one tC is
the carbon content of 413 gallons of gasoline.
26. See, for example, the discussions in Small and Verhoef (2007, ch. 3) and Parry and Small(2005). The damage estimate of $25/tC is also consistent with the “shadow price” of carbon
coming out of optimization models of economically efficient paths toward greenhouse gas
control, the most well-known being a series of models developed over many years by William
Nordhaus, of which a recent version is the regional integrated model of climate and theeconomy, or RICE model (Nordhaus 1994). Nordhaus (2007b) describes a recent calculation
using this model as leading to a carbon price of $17/tC in year 2010 (stated at year 2005
prices) rising to $70/tC in 2050. The “optimal” calibration reported in Nordhaus (2007a)
produces a price of $35/tC in 2015, $85/tC in 2050, and $206/tC in 2100. These numbers
encompass all the estimates underlying Table 5 except for Stern’s. The damage estimate canalso be compared to the actual trading prices of carbon permits in the EU’s Emissions Trading
Scheme. If the market is working smoothly (a highly debated proposition in this case), theseprices should reflect the marginal costs to industry of enacting controls to meet the mandates of
the EU under the Kyoto Protocol. In actual experience this market has fluctuated substantially,
with prices between €€ 6 and €€ 30 per tonne of carbon dioxide during a period covering most of
2004-06 (Convery and Redmond 2007, Fig. 2), which equate to $27–$138/tC (given that the
carbon atom constitutes 12/44 of the atomic weights in a molecule of CO2, and using the
average 2004-06 exchange rate of 1€€ =$1.25). These figures suggest that in Europe, at least, themarginal control cost has been pushed to well above the lower estimates of marginal damage
cost in Table 5.
27. Tol (2005) reviews 103 estimates of marginal CO2 damage costs, taken from 28 separate
studies done by 18 distinct research groups. The median estimate is $14/tC, but the estimates
are highly skewed to the right, with unweighted mean $93/tC and standard deviation $203/tC.
The mean estimate declines substantially, to $43/tC, when only peer-reviewed studies areincluded; so does the standard deviation, to $83/tC. There is a clear effect of methodology –especially using a very low interest rate for discounting and using “equity weights” toaggregate across countries – in accounting for most of the higher estimates. Tol concludes:“Using standard assumptions about discounting and aggregation, the marginal damage costs …
are unlikely to exceed $50/tC, and [are] probably much smaller” (p. 2064).
28. These numbers are calculated from Stern’s assumed 1.3 percent per year growth rate of percapita output in the absence of human-induced climate change, applied for a period of 200
years, and diminished by 35.2 percent according to the 95th-percentile loss in the worst
scenario shown, that labelled “High Climate, market impacts + risk of catastrophe + nonmarket impacts” (described on p. 156 and in Figure 6.5c). Nordhaus (2006, p. 18) makes asomewhat similar calculation in a working-paper version of his 2007 critique.
29. We have restated Stern’s figure of $85 (Stern 2006, p. 287) from year 2000 to year 2005
prices, using the 13.4% growth of US Consumer Price Index over that time.
30. The US price of coal in 2003 was $19.68 per metric ton (US EIA 2006, Table 7.8, converted tometric tons) with carbon content 0.75 (O’Hara 1990, Table 6), implying a price of $26/tC.

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LIST OF PARTICIPANTS -LIST OF PARTICIPANTS

Professor Paul R. PORTNEY
DeanEller College of Management
The University of Arizona
1130 E. Helen Street
P.O. Box 210108
Tucson, AZ 85721-0108
UNITED STATES

ChairmanProfessor Kjell ALEKLETT
Uppsala Hydrocarbon Depletion Study Group
Department of Physics and Astronomy
Uppsala University
Box 535
SE-751 21 UPPSALASWEDEN

Rapporteur

Mr. Lawrence EAGLESHead Oil Industry and Markets DivisionInternational Energy Agency
9 rue de la Fédération
75015 PARISFRANCE

RapporteurProf. David GREENE, Ph.D.
Oak Ridge National Laboratory
Centre for Transportation Analysis
National Transportation Research Center
2360 Cherahala Boulevard
KNOXVILLE, TN 37932
UNITED STATES

Rapporteur

Professor Kenneth SMALL
University of California at Irvine
Economics Department
3151 Social Science Plaza
IRVINECA. 92697-5100
UNITED STATES

Rapporteur

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202 – LIST OF PARTICIPANTS
Dr. Kurt VAN DENDER
Administrator
OECD/ITF Joint Transport Research Centre
2-4 rue Louis David
F-75016 PARISFRANCE

Co-Rapporteur

Mme Nathalie ALAZARD-TOUX
Directeur des Études Économiques
Institut Français du Pétrole
1-4 avenue de Bois-Préau
92852 RUEIL-MALMAISON Cedex
FRANCE
Dr. Roger BENTLEY
Senior Research Fellow
Department of Cybernetics
The University of Reading
Whiteknights
PO Box 217
READING, Berkshire, RG6 6AH
UNITED KINGDOM
Prof. Runar BRANNLUND
Department of Economics
Umea University
S-901 87 UMEA
SWEDENDrs. Martijn BRONSFree University Amsterdam
Department of Spatial Economics
Faculty of Economic Sciences, Business Administration and Econometrics
De Boelelaan 1105
NL-1081 HV Amsterdam
NETHERLANDS
Dr. Joyce DARGAY
Reader in Travel Demand Analysis
Institute for Transport Studies
Faculty of Environment
Room: G03 (41 UR)
University of Leeds
GB-LEEDS LS2 9JT
UNITED KINGDOMOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-82-0121-6 – © OECD/ITF, 2008

LIST OF PARTICIPANTS -Mr. Jos DINGS
Director
European Federation for Transport and Environment (T&E)
Rue de la Pépinière, 1
B-1000 BRUSSELSBELGIUM
Mrs. Sandrine DIXSON-DECLEVE
Executive Director
International Sustainable Energy Exchange (ISEE) &International Fuel Quality Centre (IFQC)
17A, Avenue du Fond Jean Rosy
B-1330 RIXENSARTBELGIUM
Ms. Naoko DOI
Head, Transport Energy Demand Sector
Asia Pacific Energy Research Centre (APERC)
Inui Building
Kachidoki 16F
1-13-1 Kachidoki
Chuo-ku,
104-0054 TOKYOJAPAN
Dr. Fereidun FESHARAKI
Chairman and CEO, FACTS Global Energy
Senior Fellow
East-West Center
1601 East West Road
HONOLULU, Hawaii 96848
UNITED STATES
Mr. Adrian GAULT
Head of Transport Analysis and Review Division
Department for Transport
Great Minster House, Zone 4/14a
76 Marsham Street
London SW1P 4DR
UNITED KINGDOM
Dr. Jonathan GUPTON
Energy Information Administration (EIA)US Department of Energy (DOE)1000 Independence Ave, SW.
WASHINGTON, DC 20585
UNITED STATESOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-82-0121-6 – © OECD/ITF, 2008

203

204 – LIST OF PARTICIPANTS
Dr. Niels Buus KRISTENSEN
Director
Danish Transport Research Institute
Danish Technical University
Knuth-Winterfeldts Alle Bygning 116 Vest
DK-2800 LYNGBY
DENMARK
Mr. Michael LYNCH
President and Director of Global Petroleum Service
Strategic Energy & Economic Research, Inc. (SEER)
14 West Chardon Road
Winchester, MA 01890
UNITED STATES
Prof. Anil MARKANDYA
Fondazione Eni Enrico Mattei
Corso Magenta 63
I-20123 MILAN
ITALYProf. Angelo MARTINO
TRT Trasporti e Territorio SRL
Via Rutila, 10/8
I-20146 MILANO
ITALYProf. Alan McKINNON
Heriot-Watt University
Logistics Research Centre
School of Management
GB-EDINBURGH EH14 4AS
UNITED KINGDOM
Dr. Imre Tamás MERÉTEIDeputy Head of Automotive Engineering,
Environmental and Energy Division
Thán Karoly u. 3-5
H-1119 BUDAPESTHUNGARY
Dr. Ulf MOSLENER
Senior Researcher
ZEW (Centre for European Economic Research)
L7,1
D-68161 MANNHEIMGERMANYOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-82-0121-6 – © OECD/ITF, 2008

LIST OF PARTICIPANTS -M. J.P. MOULINIER
Ingénieur général des Ponts et Chaussées
Ministère de l'Écologie, de l'Aménagement et du Développement Durables
Chargé de Mission Stratégie
Grande Arche de la Défense Paroi Sud
F-92055 LA DEFENSE Cedex 04
FRANCEDr Pierre NOEL
Research AssociateElectricity Policy Research Group
Judge Business School
University of Cambridge
Trumpington Street
GB-CAMBRIDGE CB2 1AG
UNITED KINGDOM
Dr. Robert NOLAND
Reader in Transport and Environmental Policy
Centre for Transport Studies
Department of Civil and Environmental Engineering
Imperial College London
GB-LONDON SW7 2AZ
UNITED KINGDOM
Mr. Nils-Anders NORDLIEN
Adviser
Ministry of Petroleum and Energy
Einar Gerhardsens Plass 1
Postboks 8148 Dep,
N-0033 OSLONORWAY
Prof. Émile QUINETChef du Département d’Économie et des Sciences
École Nationale des Ponts et Chaussées
28 rue des Saints-Pères
F-75007 PARISFRANCE
Dr. Farideh RAMJERDI
Senior Economist
Institute of Transport Economics
Gaustadalleen 21
N-0349 OSLONORWAYOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-82-0121-6 – © OECD/ITF, 2008205

206 – LIST OF PARTICIPANTS
Prof.Dr. Wolfgang SCHADE
Project Leader, Senior Analyst
Fraunhofer-Institut für System- und Innovationsforschung ISI
Nachhaltiges Wirtschaften und Infrastrukturen
Breslauer Strasse 48
D-76139 KARLSRUHEGERMANY
M. Thierry VEXIAU
Chargé de Mission - Environnement
Ministère de l'Écologie, de l'Aménagement et du Développement Durables
Grande Arche de la Défense Paroi Sud
F-92055 LA DEFENSE Cedex 04
FRANCE
Prof. Franz WIRL
Chair: Industry, Energy and Environment
University of Vienna
Brünnerstr. 72
Room 123
A-1210 VIENNA
AUSTRIA

INTERNATIONAL ENERGY AGENCY:
Mr. Pierpaolo CAZZOLAEnergy Analyst
Energy Technology Policy DivisionInternational Energy Agency (IEA)
9 rue de la Fédération
75775 PARIS CEDEX 15
FRANCE
Mr. Paul DOWLING
Energy Analyst
Economic Analysis DivisionInternational Energy Agency
9 rue de la Federation
75015 PARISFRANCEMr David FYFE
Senior Energy Analyst
Oil Industry and Markets DivisionInternational Energy Agency (IEA)
9 rue de la Fédération
75775 PARIS CEDEX 15
FRANCEOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-82-0121-6 – © OECD/ITF, 2008

LIST OF PARTICIPANTS -Mr. Lew FULTON
Senior Transport Energy Analyst
Energy Technology Policy DivisionInternational Energy Agency (IEA)
9 rue de la Fédération
75775 PARIS CEDEX 15
FRANCE
Mr. Olivier RECH
Economic Analysis DivisionInternational Energy Agency (IEA)
9 rue de la Fédération
75775 PARIS CEDEX 15
FRANCEOBSERVERS:
Mrs. Tamara KURZOVAHead of Department for Foreign Economic Relations
Ministry of Transport and Communications of Ukraine
14 Peremohy Avenue
01135 KIEVUKRAINIA
Dr. Viktor USTYMENKO
State Road Transport Research Institute
Ministry of Transport and Communications of Ukraine
14 Peremohy Avenue
01135 KIEVUKRAINIA
Mrs. Murad GURMERIC
Highways Expert
State Planning Organization
ANKARA
TURKEY
Mr. Sedef YAVUZ NOYAN
Maritime Expert
State Planning Organization
ANKARA
TURKEYOIL DEPENDENCE: IS TRANSPORT RUNNING OUT OF AFFORDABLE FUEL? – ISBN 978-92-82-0121-6 – © OECD/ITF, 2008207

208 – LIST OF PARTICIPANTS
INTERNATIONAL TRANSPORT FORUM
Mr. Alain RATHERY
Deputy Secretary General

JOINT TRANSPORT RESEARCH CENTRE OECD/ITF
Mr. Stephen PERKINSHead of Joint Transport Research Centre
Dr. Kurt VAN DENDER
Administrator, JTRC
Dr. Michel VIOLLAND
Administrator, JTRC
Mr. Jari KAUPPILA
Administrator, JTRC
Mr. Philippe CRIST
Administrator, JTRC
Mrs. Julie PAILLIEZ
Assistant, JTRC
Mlle Françoise ROULLET
Assistant, JTRC
INTERNATIONAL TRANSPORT FORUM SECRETARIAT
Mrs. Mary CRASS
Principal Administrator, ITF
Mr. Michael ZIRPEL
Principal Administrator, ITF
Mr. Brendan HALLEMAN
Administrator, ITF

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13 9

R O U N D TA B L E

This report includes an examination of the factorsthat drive oil prices in the short and long term anda discussion of the outlook for oil supply.

139

www.internationaltransportforum.org

www.oecd.org/publishing(74 2008 03 1 P1) ISBN 978-92-82-10121-6-:HSTCSC=VUVWV[:2008

R E S E AR C HThis Round Table assesses the policy instruments
available to address oil security and climate change
and examines their interaction with measures tomanage congestion and mitigate local air pollution.
A number of incompatibilities and trade-offs
are identified underlining the importance ofintegrated policy making.

T r a n s p o r t

OPEC market power is increasing as production of
conventional oil outside OPEC has reached a plateau.
Oil from tar sands in Canada and elsewhere is available
in very large quantities, and is competitive at sustained
prices above $40 a barrel. But processing such oil
doubles CO2 emissions on a well-to-wheels basis
compared to using conventional oil to fuel transport.

Oil Dependence: Is Transport Running Out
of Affordable Fuel?

Oil consumption is increasingly concentrated intransport and relatively limited fluctuations in transportdemand can have increasingly significant effects on oil
prices. Oil prices rose to all time highs at the beginningof 2008, exceeding $100 a barrel for the first timesince the 1979 oil crisis. The underlying driver was
demand for oil from rapidly developing economies
and especially China, where transport accounts forthe largest part of oil consumption.

C E N T r e

Oil Dependence:
Is Transport Running Out
of Affordable Fuel?

Oil Dependence:
Is Transport
Running Out
of Affordable Fuel?

ROUND
TABLE

13 9