**United States Senate Committee on Energy and Natural Resources**

**Oil Market Outlook and Policy Implications**

**Prepared Testimony, 10 January 2006**

**Dr Fatih Birol, Chief Economist, International Energy Agency**

Mr Chairman, Members of the Committee,

It is a privilege to address this Committee on the critical issue of the
oil market outlook and its policy implications. The energy future which
we are creating is unsustainable. If we continue as before, the energy
supply to meet the needs of the world economy over the coming years will
remain too vulnerable to failure arising from sudden supply interruption
and will cause serious environmental problems. The oil market is a
global one so it is important to provide a global context. To that end,
this testimony draws upon the *World Energy Outlook 2006*[^1], published
by the International Energy Agency.

This testimony will examine in turn the outlooks for Demand, Supply and
Investment, followed by a look at the potential impact of Alternative
Policies and Measures. I would first like to highlight the following key
points:

1.  **The world is facing twin energy-related threats: that of not
    having adequate and secure supplies of energy at affordable prices
    and that of environmental harm caused by its use.** The *World
    Energy Outlook 2006* confirms that fossil-fuel demand and trade
    flows, and greenhouse-gas emissions would follow their current
    unsustainable paths through to 2030 in the absence of new government
    action -- the underlying premise of the Reference Scenario. It also
    demonstrates, in an Alternative Policy Scenario, that a package of
    policies and measures that countries around the world are
    considering would, if implemented, significantly reduce the rate of
    increase in demand and emissions. Importantly, the economic cost of
    these policies would be more than outweighed by the economic
    benefits that would come from using and producing energy more
    efficiently.

2.  **Oil demand grows by 1.3% per year through 2030 in the Reference
    Scenario**, reaching 116 million barrels per day (mb/d) in 2030 --
    up from 84 mb/d in 2005. The pace of demand growth slackens
    progressively over the period. More than 70% of the increase in oil
    demand comes from developing countries (notably China and India),
    which see average annual demand growth of 2.5%.

3.  **The transport sector absorbs most of the increase in global oil
    demand.** In the OECD, oil use in other sectors barely increases at
    all. In developing countries too, transport contributes the bulk of
    the increase in oil demand. The lack of cost-effective substitutes
    for oil-based automotive fuels will make oil demand more rigid.

4.  **Oil supply is increasingly dominated by a small number of major
    producers**, most of them in the Middle East, where oil resources
    are concentrated. Non-OPEC production of conventional crude oil is
    set to peak within a decade. OPEC's share of global supply grows
    significantly, from 40% now to 48% by 2030. Iran and Iraq have
    significant potential to expand their production, but Saudi Arabia
    remains by far the largest producer. The need for more transparent
    and comprehensive data on oil (and gas) reserves in all regions is a
    pressing concern.

5.  **The oil industry needs to invest a total of \$4.3 trillion (in
    year-2005 dollars) over the period 2005-2030**, or \$164 billion per
    year. The upstream sector accounts for the bulk of this. Almost
    three-quarters of upstream investments will be required to maintain
    existing capacity.

6.  **A critical uncertainty is whether the substantial investments
    needed in the oil production sector in key Middle East countries
    will, in fact, be forthcoming.** These governments could choose
    *deliberately* to develop production capacity more slowly than we
    project in our Reference Scenario. Or external factors such as
    capital shortages could *prevent* producers from investing as much
    in expanding capacity as they would like. As demonstrated by a
    Deferred Investment Case, slower growth in OPEC oil production
    drives up the international oil price and, with it, the price of
    gas.

7.  **The new policies analysed in the Alternative Policy Scenario halt
    the rise in OECD oil imports by 2015.** OECD countries and
    developing Asia become more dependent on oil imports in 2030
    compared to today, but markedly less so than in the Reference
    Scenario. Global oil demand reaches 103 mb/d in 2030 in the
    Alternative Policy Scenario -- 13 mb/d lower than in the Reference
    Scenario. Additional policy measures to promote improved fuel
    efficiency of cars and trucks, as well as a greater market share for
    biofuels, therefore have the effect of improving energy security.

8.  **Our analysis demonstrates the urgency with which policy action is
    required.** Each year of delay in implementing the policies analysed
    would have a disproportionately larger effect on energy security.
    Yet there are formidable hurdles to be overcome. It will take
    considerable political will to push through the policies and
    measures in the Alternative Policy Scenario, many of which are
    likely to encounter resistance from some industry and consumer
    groups. Politicians need to spell out clearly the benefits to the
    economy and to society as a whole of the proposed measures. In most
    countries, the public is becoming familiar with the energy-security
    and environmental advantages of action to encourage more efficient
    energy use and to boost the share of renewables.

**Demand**

Primary oil demand is expected to continue to grow steadily over the
projection period in the Reference Scenario, at an average annual rate
of 1.3%. It reaches 99 mb/d in 2015 and 116 mb/d in 2030, up from 84
mb/d in 2005 (Table 1). The pace of demand growth nonetheless slackens
progressively, broadly in line with GDP, averaging 1.7% in 2005-2015 --
only just below the average of the last ten years -- and 1.1% in
2015-2030. Preliminary data for 2005 indicate that global oil demand
rose by 1.3% -- well down on the exceptionally high rate of 4% in 2004.

*Table 1: World Primary Oil Demand\* (million barrels per day)*

![](media/image1.wmf){width="5.054861111111111in"
height="5.5569444444444445in"}

Most of the increase in oil demand comes from developing countries,
where economic growth -- the main driver of oil demand -- is highest
(Figure 1). China and the rest of developing Asia account for 15 mb/d,
or 46%, of the 33-mb/d increase in oil use between 2005 and 2030, in
line with rapid economic growth. At 3.4% per year on average, China's
rate of oil-demand growth is nonetheless below the 5.1% rate of
1980-2004. The Middle East, which experiences the fastest rate of demand
growth, accounts for a further 3.8 mb/d. Higher oil revenues than in the
last two decades boost economic activity, incomes and, together with
subsidies, demand for oil. Demand in OECD countries, especially in
Europe and the Pacific region, rises much more slowly. Nonetheless, the
absolute increase in North America -- 5.9 mb/d over the *Outlook* period
-- is the second-largest of any region, because it is already by far the
largest consumer. The economies of non-OECD countries will remain
considerably more oil-intensive, measured by the amount of oil used per
unit of gross domestic product (at market exchange rates), than those of
OECD countries.

*Figure 1: Incremental World Oil Demand by Region and Sector in the
Reference Scenario, 2004-2030*

![](media/image2.png){width="5.451968503937008in"
height="3.895669291338583in"}

The transport sector absorbs 63% of the increase in global oil demand in
2004-2030. In the OECD, oil use in other sectors hardly increases at
all, declining in power generation and in the residential and services
sectors, and growing in industry. Most of the increase in energy demand
in non-transport sectors is met by gas, coal, renewables and
electricity. In non-OECD countries, too, transport is the biggest
contributor to oil-demand growth; but other sectors -- notably industry
-- also see significant growth.

**Supply**

**Resources and Reserves**

According to the Oil and Gas Journal, the world's proven reserves[^2] of
oil (crude oil, natural gas liquids, condensates and non-conventional
oil) amounted to 1 293 billion barrels[^3] at the end of 2005 -- an
increase of 14.8 billion barrels, or 1.2%, over the previous year.
Reserves are concentrated in the Middle East and North Africa (MENA),
together accounting for 62% of the world total. Saudi Arabia, with the
largest reserves of any country, holds a fifth. Of the twenty countries
with the largest reserves, seven are in the MENA region (Figure 2).
Canada has the least developed reserves, sufficient to sustain current
production for more than 200 years. The world's proven reserves,
including non-conventional oil, could sustain current production levels
for 42 years.

*Figure 2: Top Twenty Countries' Proven Oil Reserves, end-2005*

![](media/image3.wmf){width="5.095138888888889in"
height="4.4215277777777775in"}

Proven reserves have grown steadily in recent years in volume terms, but
have remained broadly flat as a percentage of production. Since 1986,
the reserves-to-production, or R/P, ratio has fluctuated within a range
of 39 to 43 years. A growing share of the additions to reserves has been
coming from revisions to estimates of the reserves in fields already in
production or undergoing appraisal, rather than from new discoveries.
Some of these revisions have resulted from higher oil-price assumptions,
allowing some oil that is known to exist to be reclassified as
economically exploitable and, therefore, moved into the proven category.
The application of new technology has also improved reservoir management
and boosted recovery rates. The amount of oil discovered in new
oilfields has fallen sharply over the past four decades, because of
reduced exploration activity in regions with the largest reserves and,
until recently, a fall in the average size of fields discovered. These
factors outweighed an increase in exploration success rates.

Over the past ten years, drilling has been concentrated in North
America, a mature producing region with limited potential for new
discoveries. Less than 2% of new wildcat wells drilled were in the
Middle East, even though the region is thought to hold over 30% of the
world's undiscovered crude oil and condensates and is where the average
size of new fields discovered in the ten years to 2005 have been higher
than anywhere else (Figure 3).

*Figure 3: Undiscovered Oil Resources and New Wildcat Wells
Drilled,1996-2005*

![](media/image4.wmf){width="5.346527777777778in"
height="4.120833333333334in"}

There has been a recent increase in the average size of new discoveries
for each new wildcat well drilled, bucking the trend of much of the
period 1965-1998. The size of newly discovered fields has continued to
decline, largely because exploration and appraisal activity has been
focused on existing basins. However, the application of new technology,
such as 3D seismic, has increased the discovery success rate per wildcat
well, particularly since 1998 -- boosted by rising global oil demand and
a resulting increase in exploration and appraisal activity -- and, to a
lesser extent, since 1991, with the advent of deep-water exploration
(Figure 4). Nonetheless, the average size of discoveries per wildcat
well -- at around 10 million barrels -- remains barely half that of the
period 1965-1979. The reduction almost to zero of Middle East
exploration, where discoveries had been largest, was the main reason for
the lower average size of discoveries since the 1980s.

*Figure 4: Cumulative Oil and Gas Discoveries and New Wildcat Wells*

![](media/image5.wmf){width="5.175in" height="3.1902777777777778in"}

Exploration and appraisal drilling is expected to increase to offset
rising decline rates at existing fields and the consequent need to
develop new reservoirs -- particularly in MENA, where some of the
greatest potential for finding new fields exists. Proven reserves are
already larger than the cumulative production needed to meet rising
demand until at least 2030. But more oil will need to be added to the
proven category if production is not to peak before then. According to
the US Geological Survey, undiscovered conventional resources that are
expected to be economically recoverable could amount to 880 billion
barrels (including natural gas liquids, or NGLs) in its mean case (USGS,
2000). Together with reserves growth and proven reserves, remaining
ultimately recoverable resources are put at just under 2 300 billion
barrels. That is more then twice the volume of oil -- 1 080 billion
barrels -- that has so far been produced. Total non-conventional
resources, including oil sands in Canada, extra-heavy oil in Venezuela
and shale oil in the United States and several other countries, are
thought to amount to at least 1 trillion barrels (WEC, 2004).

*Table 2: World Oil Supply (million barrels per day)*

![](media/image6.wmf){width="5.051388888888889in"
height="7.471527777777778in"}

![](media/image7.wmf){width="5.051388888888889in"
height="7.513194444444444in"}

**Production**

In the Reference Scenario, conventional oil production continues to be
dominated by a small number of major producers in those countries where
oil resources are concentrated. The share of production controlled by
members of the Organization of the Petroleum Exporting Countries,
particularly in the Middle East, grows significantly.[^4] Their
collective output of crude oil, NGLs and non-conventional oil grows from
34 mb/d in 2005 to 42 mb/d in 2015 and 56 mb/d in 2030, boosting their
share of world oil supply from 40% now to 48% by the end of the
*Outlook* period. Non-OPEC production increases much more slowly, from
its current level of 48 mb/d to 55 mb/d in 2015 and 58 mb/d in 2030
(Table 2). Conventional oil accounts for the bulk of the increase in oil
supply between 2005 and 2030, but non-conventional resources play an
increasingly important role (Figure 5). The projections to 2010 take
account of current, sanctioned and planned upstream projects.

*Figure 5: World Oil Supply by Source*

![](media/image8.wmf){width="5.461111111111111in"
height="4.004861111111111in"}

Production in OPEC countries, especially in the Middle East, is expected
to increase more rapidly than in other regions, because their resources
are much larger and their production costs are generally lower. Saudi
Arabia remains by far the largest producer of crude oil and NGLs. Its
total output of crude and NGLs grows from 10.9 mb/d in 2005, to 13.7
mb/d in 2015 and to 17.6 mb/d in 2030 (including Saudi Arabia's
half-share of Neutral Zone production). Most of the rest of the increase
in OPEC production comes from Iraq, Iran, Kuwait, the United Arab
Emirates, Libya and Venezuela. Other OPEC countries struggle to lift
output, with production dropping in Qatar, Algeria and Indonesia. These
projections are broadly commensurate with proven reserves. OPEC's price
and production policies and national policies on developing reserves are
extremely uncertain.

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 (Figure 6). Production in several mature regions, including
North America and the North Sea, which has been in steady decline in
recent years, stabilises or rebounds in the near term. This reflects
several factors, including the restoration of production capacity lost
through hurricanes and other technical difficulties, and the impact on
increased drilling to boost production in response to recent oil-price
increases. But this trend is expected to be short-lived, as relatively
high decline rates and rising costs soon drive output back down again.
In the longer term, only Russia, Central Asia, Latin America and
sub-Saharan Africa -- including Angola and Congo -- achieve any
significant increases in conventional oil production.

*Figure 6: Non-OPEC Conventional Crude Oil and NGLs Production*

![](media/image9.wmf){width="5.461111111111111in"
height="3.4854166666666666in"}

A lack of reliable information on production decline rates makes it
difficult to project new gross capacity needs. A high natural decline
rate -- the speed at which output would decline in the absence of any
additional investment to sustain production -- increases the need to
deploy technology at existing fields to raise recovery rates, to develop
new reserves and to make new discoveries. Our analysis of capacity needs
is based on estimates of year-on-year natural decline rates averaged
over all currently producing fields in a given country or region. The
rates assumed in our analysis vary over time and by location. They range
from 2% per year to 11% per year, averaging 8% for the world over the
projection period.[^5] Rates are generally lowest in regions with the
best production prospects and the highest R/P ratios. For OPEC, they
range from 2% to 7%. They are highest in mature OECD producing areas,
where they average 11%.

The average quality of crude oil produced around the world is expected
to become heavier (lower API gravity) and more sour (higher sulphur
content) over the Outlook period.[^6] This is driven by several factors,
including the continuing decline in production from existing sweet
(low-sulphur) crude oilfields, increased output of heavier crude oils in
Russia, the Middle East and North Africa (Figure 7), and the projected
growth of heavy non-conventional oil output. This trend, together with
increasing demand for lighter oil products and increasing fuel-quality
standards, is expected to increase the need for investment in upgrading
facilities in refineries.

*Figure 7: Gravity and Sulphur Content of Selected Crude Oil, 2005*

![](media/image10.wmf){width="5.45625in" height="3.4194444444444443in"}

**Investment**

Cumulative global investment in the oil sector amounts to about \$4.3
trillion (in year-2005 dollars) over the period 2005-2030, or \$164
billion per year, in the Reference Scenario. Investment relative to
increases in capacity is highest in OECD countries, where unit costs and
production decline rates are high compared with most other regions.
Projected oil (and gas) investment needs in this *Outlook* are higher
than in previous editions, largely because of the recent unexpected
surge in the cost of materials, equipment and skilled personnel. Unit
costs are assumed to fall back somewhat after 2010, as oil-services
capacity increases and exploration, development and production
technology improves. Upstream investment accounts for 73% of total
oil-industry investment.

The required rate of capital spending over the projection period is
substantially higher than actual spending in the first half of the
current decade, which averaged little more than \$100 billion per year.
Investment needs increase in each decade of the projection period as
existing infrastructure becomes obsolete and demand increases. Our
analysis of the spending plans of the world's leading oil and gas
companies through to 2010 shows that they expect their spending to be
much higher in the second half of the current decade than the first.

**Upstream Investment**

Upstream oil spending -- more than 90% of which is for field development
and the rest for exploration -- averages \$125 billion per year (Figure
8). Three-quarters of this investment is needed to maintain the current
level of capacity in the face of natural declines in capacity at
producing fields as reserves are depleted. This investment goes to
drilling new wells, to working over existing wells at currently
producing fields or to developing new fields. In fact, investment needs
are far more sensitive to changes in natural decline rates than to the
rate of growth of demand for oil.

*Figure 8: Cumulative Oil Investment by Activity in the Reference
Scenario, 2005-2030*

![](media/image11.wmf){width="5.461111111111111in" height="3.69375in"}

**Downstream Investment**

Cumulative investment in oil refining amounts to around \$770 billion
(\$30 billion per year) in the Reference Scenario. These projections
include the investment needed to meet demand growth and additional
spending on conversion capacity so that existing refineries are able to
meet the changing mix of oil-product demand. Tighter fuel-quality
standards aimed at mitigating the environmental impact of fuel use are
also obliging the refining industry to invest in new quality-enhancement
capacity. The required level of refining capacity, allowing for normal
maintenance shutdowns, rises from 85 mb/d in 2004 to 117 mb/d in 2030.
The largest investments occur in the Middle East and developing Asia
(Figure 9). Most new refineries will be built outside the OECD (see
below).

*Figure 9: Cumulative Investment in Oil Refining by Region, 2005-2030*

![](media/image12.wmf){width="5.45625in" height="3.0833333333333335in"}

Although investment in oil tankers and inter-regional pipelines makes up
a small proportion of total investment needs to 2030, the sum required
rises rapidly throughout the projection period, because of the need to
replace a large share of the world's ageing tanker fleet. Total
cumulative capital spending amounts to around \$260 billion. Investment
in gas-to-liquids plants in 2005-2030 is expected to amount to \$100
billion. Most of this investment occurs in the second half of the
projection period. Investment in commercial coal-to-liquids plants,
mostly in China, is projected to total over \$30 billion.

**Investment Uncertainties and Challenges**

Over the period to 2010, the total amount of investment that will be
made in oil and gas infrastructure is known with a reasonable degree of
certainty. Investment plans may change in response to sudden changes in
market conditions and some projects may be cancelled, delayed or
accelerated for various reasons. But the actual gross additions to
supply capacity at various points along the oil-supply chain are
unlikely to depart much from those projected in this *Outlook*. However,
beyond 2010, there is considerable uncertainty about the prospects for
investment, costs and the rate of capacity additions. The opportunities
and incentives for private and publicly-owned companies to invest are
particularly uncertain. Environmental policies could increasingly affect
opportunities for building upstream and downstream facilities and their
cost, especially in OECD countries. In the longer term, technological
developments could open up new opportunities for investment and help
lower costs.

The availability of capital is unlikely to be a barrier to upstream
investment in most cases. But opportunities and incentives to invest may
be. Most privately-owned international oil and gas companies have large
cash reserves and are able to borrow at good rates from capital markets
when necessary for new projects. But those companies may not be able to
invest as much as they would like because of restrictions on their
access to oil and gas reserves in many resource-rich countries. Policies
on foreign direct investment will be an important factor in determining
how much upstream investment occurs and where.

A large proportion of the world's reserves of oil are found in countries
where there are restrictions on foreign investment (Figure 10). Three
countries -- Kuwait, Mexico and Saudi Arabia -- remain totally closed to
upstream oil investment by foreign companies. Other countries are
reasserting state control over the oil industry. Bolivia recently
renationalised all its upstream assets. Venezuela effectively
renationalised 565 kb/d of upstream assets in April 2006, when the
state-owned oil company, PdVSA took over 115 kb/d of private production
and took a majority stake in 25 marginal fields producing 450 kb/d after
the government unilaterally switched service agreements from private to
mixed public-private companies. The Russian government has tightened its
strategic grip on oil and gas production and exports, effectively ruling
out foreign ownership of large fields and keeping some companies,
including Transneft, Gazprom and Rosneft, in majority state ownership.
Several other countries, including Iran, Algeria and Qatar, limit
investment to buy-back or production-sharing deals, whereby control over
the reserves remains with the national oil company.

*Figure 10: Access to World Proven Oil Reserves, end-2005*

![](media/image13.wmf){width="5.350694444444445in"
height="3.4291666666666667in"}

Even where it is in principle possible for international companies to
invest, the licensing and fiscal terms or the general business climate
may discourage investment. Most resource-rich countries have increased
their tax take in the last few years as prices have risen. The stability
of the upstream regime is an important factor in oil companies'
evaluation of investment opportunities. War or civil conflict may also
deter companies from investing. No major oil company has yet decided to
invest in Iraq. Geopolitical tensions in other parts of the Middle East
and in other regions may discourage or prevent inward investment in
upstream developments and related LNG and export-pipeline projects.

National oil companies, especially in OPEC countries, have generally
increased their capital spending rapidly in recent years in response to
dwindling spare capacity and the increased financial incentive from
higher international oil prices. But there is no guarantee that *future*
investment in those countries will be large enough to boost capacity
sufficiently to meet the projected call on their oil in the longer term.
OPEC producers generally are concerned that overinvestment could lead to
a sharp increase in spare capacity and excessive downward pressure on
prices. Sharp increases in development costs are adding to the arguments
for delaying new upstream projects. For example, two planned GTL plants
in Qatar were put on hold by the government in 2005 in response to
soaring costs and concerns about the long-term sustainability of
production from the North field. An over-cautious approach to investment
would result in shortfalls in capacity expansion.

Environmental policies and regulations will increasingly affect
opportunities for investment in, and the cost of, new oil projects. Many
countries have placed restrictions on where drilling can take place
because of concerns about the harmful effects on the environment. In the
United States, for example, drilling has not been allowed on large
swathes of US federal onshore lands -- such as the Arctic National
Wildlife Refuge (ANWR) -- and offshore coastal zones for many years.[^7]
Even where drilling is allowed, environmental regulations and policies
impose restrictions, driving up capital costs and causing delays. The
likelihood of further changes in environmental regulations is a major
source of uncertainty for investment.

Local public resistance to the siting of large-scale, obtrusive
facilities, such as oil refineries and GTL plants, is a major barrier to
investment in many countries, especially in the OECD. The
not-in-my-backyard (NIMBY) syndrome makes future investments uncertain.
It is all but impossible to obtain planning approval for a new refinery
in many OECD countries, though capacity expansions at existing sites are
still possible. The risk of future liabilities related to site
remediation and plant emissions can also discourage investment in oil
facilities. The prospect of public opposition may deter oil companies
from embarking on controversial projects. Up to now, NIMBY issues have
been less of a barrier in the developing world.

Technological advances offer the prospect of lower finding and
production costs for oil and gas, and opening up new opportunities for
drilling. But operators often prefer to use proven, older technology on
expensive projects to limit the risk of technical problems. This can
slow the deployment of new technology, so that it can take decades for
innovative technology to be widely deployed, unless the direct cost
savings are clearly worth the risk. This was the case with the rotary
steerable motor system, which has finally become the norm for drilling
oil and gas wells. These systems were initially thought to be less
reliable and more expensive, even though they could drill at double or
even triple the rate of penetration of previous drilling systems. The
slow take-up of technology means that there are still many regions where
application of the most advanced technologies available could make a big
impact by lowering costs, increasing production and improving recovery
factors. For example, horizontal drilling, which increases access to and
maximises the recovery of hydrocarbons, is rarely used in Russia.

As well as lowering costs, technology can be used to gain access to
reserves in ever more remote and hostile environments -- such as arctic
regions and deep water -- and to increase production and recovery rates.
New technology has enabled the subsurface recovery of oil from tar sands
using steam-assisted gravity drainage and closely placed twin horizontal
wells, while enhanced oil recovery has been made possible by injecting
CO~2~ into oil wells and by using down-hole electrical pumps, to allow
oil to be produced when the reservoir pressure is insufficient to force
the oil to the surface.

Although costs have risen sharply in recent years, much of the world's
remaining oil can still be produced at costs well below current oil
prices. Most major international oil companies continue to use a crude
oil price assumption of \$25 to \$35 per barrel in determining the
financial viability of new upstream investment. This conservative figure
by comparison with current high oil prices partly reflects caution over
the technical risks associated with large-scale projects and the
uncertainty associated with long lead times and the regulatory
environment.

The current wave of upstream oil investment is characterised by a heavy
focus on such projects, involving the development of reserves that were
discovered in the 1990s or earlier. Unless major new discoveries are
made in new locations, the average size of large-scale projects and
their share in total upstream investment could fall after the end of the
current decade. That could drive up unit costs and, depending on prices
and upstream-taxation policies, constrain capital spending. Capital
spending may shift towards more technically challenging projects,
including those in arctic regions and in ultra-deep water. The
uncertainties over unit costs and lead times of such projects add to the
uncertainty about upstream investment in the medium to long term.

**Implications of Deferred Upstream Investment**

In light of the uncertainties described above, we have developed a
Deferred Investment Case to analyse how oil markets might evolve if
upstream oil investment in OPEC countries over the projection period
were to increase much more slowly than in the Reference Scenario. This
could result from government decisions to limit budget allocations to
national oil companies or other constraints on the industry's ability or
willingness to invest in upstream projects. For the purposes of this
analysis, it is assumed that upstream oil investment in each OPEC
country proportionate to GDP remains broadly constant over the
projection period at the estimated level of the first half of the
current decade of around 1.3%. This yields a reduction in cumulative
OPEC upstream investment in the Deferred Investment Case vis-à-vis the
Reference Scenario of \$190 billion, or 25%, over 2005-2030. Upstream
investment still grows in absolute terms.

Lower oil investment inevitably results in lower OPEC oil production.
This is partially offset by increased non-OPEC production. Higher oil
prices encourage this increased investment and production in non-OPEC
countries. They also cause oil demand to fall relative to the Reference
Scenario. Higher prices for oil and other forms of energy also reduce
GDP growth marginally, pushing demand down further. In 2030, the
international crude oil price, for which the average IEA import price
serves as a proxy, is \$19 higher in year-2005 dollars and \$33 higher
in nominal terms (assuming annual inflation of 2.3%) than in the
Reference Scenario -- an increase of about 34%.

As a result of higher prices and lower GDP growth, the average annual
rate of global oil-demand growth over 2005-2030 falls from 1.3% in the
Reference Scenario to 1.1% in the Deferred Investment Case. By 2030, oil
demand reaches 109 mb/d -- some 7 mb/d, or 6%, less than in the
Reference Scenario (Figure 11). This reduction is equal to more than the
current oil demand of China. Higher oil prices encourage consumers to
switch to other fuels, use fewer energy services and reduce waste. They
encourage faster improvements in end-use efficiency. In the transport
sector, they also encourage faster deployment of biofuels and other
alternative fuels and technologies, such as hybrids. The size of these
effects varies among regions. It is highest in non-OECD countries,
because the share of non-transport uses in final demand (which is
relatively price-elastic) is higher there than in the OECD and because
the share of taxes, which blunt the impact on demand of higher
international oil prices, is generally lower.

*Figure 11: Reduction in World Oil Demand and OPEC Market Share*

![](media/image14.wmf){width="5.461111111111111in"
height="3.6041666666666665in"}

The drop in world oil demand that results from higher prices is
accompanied by an equivalent decline in world production in the Deferred
Investment Case. Unsurprisingly, OPEC oil production falls sharply in
response to much lower investment (Figure 12). Including NGLs, OPEC
output is just over 11 mb/d lower in 2030 than in the Reference
Scenario, though, at 45 mb/d, it is still nearly 12 mb/d higher than in
2005. OPEC's share of world oil production remains essentially flat at
about 40% over the projection period. In the Reference Scenario, the
share rises to 48% in 2030.

The fall in OPEC production is largely offset by higher non-OPEC output,
which climbs to 64 mb/d -- some 4 mb/d higher than in the Reference
Scenario and 14 mb/d higher than in 2005. Higher prices stimulate faster
development of conventional and non-conventional reserves in all
non-OPEC regions, as marginal fields become more commercial. About 1
mb/d, or 15%, of the increase in non-OPEC output comes from oil-sands in
Canada. As a result, the share of non-conventional oil in total world
supply increases from 2% in 2005 to more than 9% in 2030, compared with
less than 8% in the Reference Scenario.

*Figure 12: World Oil Production in the Deferred Investment Case
Compared with the Reference Scenario*

![](media/image15.wmf){width="5.461111111111111in"
height="3.4138888888888888in"}

**Alternative Policy Scenario**

The Reference Scenario presents a sobering vision of the next
two-and-a-half decades, as the major oil-consuming regions -- including
the United States -- become even more reliant on imports, often from
distant, unstable parts of the world along routes that are vulnerable to
disruption.

In July 2005, G8 leaders, meeting at Gleneagles with the leaders of
several major developing countries and heads of international
organisations, including the IEA, recognised that current energy trends
are unsustainable and pledged themselves to resolute action to combat
rising consumption of fossil fuels and related greenhouse-gas emissions.
They called upon the IEA to, "advise on alternative energy scenarios and
strategies aimed at a clean, clever, and competitive energy future". The
Alternative Policy Scenario presented in the *World Energy Outlook 2006*
is a direct response to that request, which the G8 reaffirmed in July
2006 in St. Petersburg.

The Alternative Policy Scenario analyses how far policies and measures
currently under discussion[^8] can take us in dealing with the grave
energy challenges now being faced. Information on more than 1,400
proposed policies and measures has been collected and analysed. Sectoral
and regional effects were also analysed in detail, in order to help
identify the actions that can work best, quickest and at least cost.

The results of this analysis are clear: First, implementing the policies
and measures that governments are currently considering would lead to
significantly slower growth in both fossil-fuel demand and CO~2~
emissions. Second, new policies and measures would pay for themselves --
the financial savings far exceed the initial extra investment cost for
consumers.

**Demand in the Alternative Policy Scenario**

In the Alternative Policy Scenario, the implementation of more
aggressive policies and measures significantly curbs the growth in total
primary and final energy demand -- a reduction of about 10% relative to
the Reference Scenario. That saving is roughly equal to the current
energy demand of China. Demand still grows, by 37% between 2004 and
2030, but more slowly: 1.2% annually against 1.6% in the Reference
Scenario.

The reduction in the use of fossil fuels such as oil is even more marked
than the reduction in primary energy demand (Figure 13). It results from
the introduction of more efficient technologies and switching to
carbon-free energy sources. Nonetheless, fossil fuels still account for
77% of primary energy demand by 2030 (compared with 81% in the Reference
Scenario).

*Figure 13: Incremental Demand and Savings in Fossil Fuels in the
Alternative Policy Scenario, 2004-2030*

![](media/image16.wmf){width="5.45625in" height="3.104861111111111in"}

Global demand for oil in the Alternative Policy Scenario grows on
average by 0.9% per year, reaching 103 mb/d in 2030 -- an increase of 20
mb/d on 2005 levels, but 13 mb/d (11%) lower than in the Reference
Scenario. In 2030, the share of oil in total primary energy demand is
32% in the Alternative Policy Scenario, a drop of three percentage
points compared to 2004. By 2015, oil demand will be 15% higher than in
2004, compared to 21% in the Reference Scenario. Increased fuel
efficiency in new vehicles, together with the faster introduction of
alternative fuels and vehicles, accounts for more than half of the oil
savings in the Alternative Policy Scenario. Most of the rest comes from
savings in oil use in the industry and building sectors.

These savings are equivalent to the current combined production of Saudi
Arabia and Iran (Table 3). By 2015, demand reaches 95 mb/d, a reduction
of almost 5 mb/d on the Reference Scenario. Measures in the transport
sector -- notably those that boost the fuel economy of new vehicles --
contribute 59% of the savings over the projection period. Increased
efficiency in industrial processes accounts for 13%, and fuel switching
in the power sector and lower demand from other energy-transformation
activities, such as heat plants and refining, for 9%. More efficient
residential and commercial oil use makes up the rest.

*Table 3: World Oil Demand in the Alternative Policy Scenario\* (mb/d)*

![](media/image17.wmf){width="4.936805555555556in"
height="5.395833333333333in"}

**Supply in the Alternative Policy Scenario**

In principle, lower global oil demand in the Alternative Policy Scenario
would be expected to result in a lower oil price than in the Reference
Scenario. Production in higher-cost fields mainly located in OECD
countries, would be reduced, declining even more rapidly after 2010 than
in the Reference Scenario. But concerns about the security of supply
might encourage OECD and other oil-importing countries to take action to
stimulate development of their own oil resources. For example, the UK
government is currently considering such policies (DTI, 2006) and the US
Congress is considering allowing more offshore oil exploration and
giving royalty relief for offshore production. For these reasons, we
assumed that oil production in OECD and other net oil-importing
countries -- as well as the international crude oil price -- remain at
the same levels as in the Reference Scenario. As a result, the call on
oil supply from the net exporting countries is reduced in the
Alternative Policy Scenario. OPEC members and major non-OPEC producing
regions, including Russia, the Caspian region and west Africa, are most
affected (Figure 14). OPEC production reaches 38.8 mb/d in 2015 and 45.1
mb/d in 2030. The average growth of 1.2% per year is just over half the
growth in the Reference Scenario. OPEC's share of the global oil market
rises from the current 40% to nearly 44% in 2030, but this is five
percentage points lower than that in the Reference Scenario.

*Figure 14: Oil Supply in the Alternative Policy Scenario*

![](media/image18.wmf){width="5.350694444444445in"
height="3.3826388888888888in"}

Crude oil production outside OPEC is projected to increase from 50 mb/d
in 2005 to 56 mb/d in 2015 and 58.3 mb/d in 2030 (though 1.8 mb/d or 3%
lower than in the Reference Scenario). The transition economies are
expected to account for half of this increase. Latin America and West
Africa account for most of the remainder. Production in OECD countries
is expected to decline steadily from 2010 onwards, as in the Reference
Scenario. The share of non-conventional oil production in this scenario
in 2030, at 8.7%, is an increase of 7.4 mb/d over current levels. The
production of biofuels is also expected to increase substantially,
especially in oil importing countries. Globally, biofuel production will
grow almost 10 times, from 15 Mtoe in 2004 to 147 Mtoe in 2030. Most of
the additional growth, over and above Reference Scenario levels, is
expected to occur in the United States and the European Union.

[^1]: The *World Energy Outlook* series is the leading source for
    medium- to long-term energy market analysis and has achieved
    widespread international recognition. It is the annual flagship
    publication of the International Energy Agency. The latest edition
    was released on 7 November 2006.

[^2]: Oil that has been discovered and is expected to be economically
    producible is called a proven reserve. Oil that is thought to exist,
    and is expected to become economically recoverable, is called a
    resource. Total resources include existing reserves, "reserves
    growth" -- increases in the estimated size of reserves as fields are
    developed and produced -- and undiscovered resources. Comparison of
    reserves and resource assessments is complicated by differences in
    estimation techniques and assumptions among countries and companies.
    In particular, assumptions about prices and technology have a major
    impact on how much oil is deemed to be economically recoverable.

[^3]: *Oil and Gas Journal* (19 December 2005). Includes proven
    oil-sands reserves in Canada.

[^4]: OPEC is assumed to be willing to meet the portion of global oil
    demand not met by non-OPEC producers at the prices assumed (see
    Chapter 1). A special analysis of the effect of lower OPEC
    investment in upstream capacity is presented at the end of this
    chapter.

[^5]: These rates are based on information obtained in consultations
    with international and national oil companies, oilfield service
    companies and consultants. Observed decline rates are generally much
    lower, as they reflect investment to maintain or boost output at
    existing fields.

[^6]: However, upstream projects under development may result in a
    marginal reduction in the sulphur content and a small increase in
    the API gravity of installed crude oil production capacity in the
    next five years, according to the IEA's Oil Market Report (12
    September 2006).

[^7]: In mid-2006, Congress was considering a bill to open up 8% of
    ANWR.

[^8]: An example for the US would be the implementation of the reform of
    CAFE standards proposed by the National Highway Traffic Safety
    Administration.