Gasoline prices in the USA
have been setting new records despite the fact that the driving season is still
several weeks away. Part of the
explanation for this year’s high prices is the general growth in demand, added
to which is the fact that domestic refinery capacity is hardly growing at all,
while gasoline inventories are also low.
A further factor, however, is the change in gasoline specifications
introduced at the start of the year. New
limits were imposed on the sulphur level in gasoline and three states banned
the use of an important additive, methyl tertiary butyl ether (MTBE). Since the USA
is the world’s largest gasoline market and an importer of gasoline, these
changes are having an impact well beyond the borders of the USA,
as far afield as Europe and even Asia.
Growing demand
The US Department of Energy expects domestic gasoline demand
to average 9.3 mn bpd in 2004.
This represents a 4% increase over 2003 and is taking place despite this
year’s record price levels. Gasoline
accounts for the largest proportion of the USA’s
demand barrel (see Table A) and the US
gasoline market is by far the world’s largest, accounting for nearly 40% of
world gasoline demand.
The growth in
demand, combined with the low level of inventories, has propelled US gasoline
prices to record highs this spring.
Gasoline futures exceeded $1.24 a gallon in April, setting new records
for the New York Mercantile Exchange (Nymex).
High gasoline prices have also played a role in pushing US crude prices over
$40 a barrel.
Table A
USA: Refined
product demand, 2003
|
Product
|
Volume
|
Market Share
|
|
|
(mn bpd)
|
(%)
|
|
Gasoline
|
8.96
|
44.6
|
|
Jet fuel
|
1.58
|
7.9
|
|
Heating
oil
|
3.94
|
19.6
|
|
Residual
fuel oil
|
0.78
|
3.9
|
|
Others
|
4.81
|
24.0
|
|
Total
|
20.07
|
100.0
|
Source: US
Energy Information Administration
Strong US
gasoline demand has driven up prices elsewhere, particularly in Europe,
which is an important supplier of gasoline and gasoline components to the USA
(see ‘Focus’, March 2004). The US
market has even helped to support gasoline prices in East Asia,
which supplies product to the US West Coast and Gulf
Coast.
The situation in
the USA has
been made worse by this year’s cold winter, which delayed the switch by
refiners from making heating oil to raising their output of gasoline in order
to build up inventories in advance of the summer driving season. As a result, oil industry stocks of gasoline
are lower than expected. At the end of
April, stocks amounted to 200 mn bbl: 3% below year-earlier levels
and 4% below the five-year average.
Another factor
in creating shortages is the slow rate at which refining capacity is
increasing. Environmental controls make
it almost impossible to build refineries on greenfield sites; so all the
expansion is coming from the modernization, extension and debottlenecking of
existing refineries. Such capacity
increases, however, have slowed down markedly in the past two years. There are even plans to close some
refineries.
In September
this year, Shell will close its 70-year-old, 66,000 bpd refinery at Bakersfield,
California.
As well as being the largest gasoline market in the USA,
California is also a net importer
of motor spirit. Refiners in the state
of Washington say they will
increase exports to California,
but there is considerable doubt over the ability of marine terminals in the
Seattle-Puget Sound area to handle the extra volume.
Elsewhere in the
USA, small
refineries are being marked down for closure, either because of their size or their
inability to afford the investment needed to produce the new fuel
specifications demanded by federal and state legislators (see below). A survey by the Oil & Gas Journal reported the
closure of two US
refineries in 2003: the 30,000 bpd American International Refining plant
at Lake Charles, Louisiana,
and another 30,000 bpd unit in the same state, the Church Point refinery,
owned by the Canal Refining Company.
Changing specs
US
gasoline’s problems are as much political as they are to do with demand and
supply. Indeed, gasoline is the most
political product in what is more generally a highly politicized industry: and
nowhere is this more so than in California.
The politics of
gasoline are closely bound up with issues of air quality. In the 1980s, California’s
legislators began to address seriously the problem of photo-chemical smogs in
the Los Angeles Basin. Here, temperature inversions frequently
trapped tailpipe emissions from motor vehicles, causing dense and often choking
smogs. A number of bodies at both the
local and state level began to press for changes in the specification of motor
gasoline in order to alleviate the problem, among which was the highly
influential California Air Resources Board (CARB).
The upshot of
these events was a series of proposals aimed at improving the combustion
properties of gasoline in order to reduce the concentration of pollutants in
the atmosphere. Similar issues were
taken up by other US
states until, in 1990, a comprehensive clean air act was signed into law covering
the entire USA. Among the requirements of the act were
minimum levels for the oxygen content of gasoline that were designed to make
combustion more efficient. These
specified a 2.0% minimum content by weight, with a higher limit of 2.7% in
winter for the most polluted areas of the USA. Such gasoline became known as ‘reformulated
gasoline’ and it accounted for round about one third of the entire US
gasoline market.
The oxygen was
added to the fuel in the form of compounds containing oxygen known as
oxygenates. These included methyl
tertiary butyl ether (MTBE), which could be made from natural gas, and ethanol,
made from corn. Such compounds
constituted about 10% of the reformulated gasoline by volume. They were thus seen by many politicians as
not only improving the air quality of many US cities, but also as reducing the
volume of crude oil required to manufacture gasoline, and thereby helping to
keep down US imports of crude.
The rise and fall of MTBE
MTBE proved the most popular of the various oxygenates,
especially in California. Not only did it provide the necessary oxygen
content for gasoline, it also improved octane levels. It also provided a market for methanol, a
gas-based product then in oversupply, and isobutylene, a by-product from refinery
and petrochemical cracking units.
Its use spread
to other parts of the world, including parts of Latin America,
the Middle East and the Asia/Pacific region, becoming
the fastest-growing chemical of the early 1990s. In some European markets, MTBE was added to
petrol to replace the octane lost when lead was eliminated from motor
spirit. Production capacity grew in the USA
to meet both domestic demand and a growing trade with Latin America. Capacity grew even faster outside the USA,
however, as countries such as Saudi Arabia
and Malaysia
set themselves up as suppliers to the burgeoning US
market. By 2000, production capacity
worldwide had reached 0.6 mn bpd.
Consumption by then was only 0.5 mn bpd, though many expected
it to rise as other countries opted for the oxygenate.
About this time,
however, serious doubts were beginning to emerge in the USA
about the role of MTBE. California,
in particular, was beginning to have second thoughts. In some areas, such as Alaska,
it was claimed that the use of MTBE actually increased levels of air
pollution. The main issue in California,
however, was the contamination of some of the state’s water supplies by MTBE.
By this time, California
accounted for more than a third of US
consumption of MTBE, then around 0.3 mn bpd. Studies by the California Energy Commission
and others found traces of the oxygenate in lakes and
groundwater. In the first place, the
origin appeared to be power-boats and jet skis with inefficient two-stroke
engines, which emitted MTBE and unburned hydrocarbons into the lake
waters. Rather than seeking to ban the
water craft, however, the state’s politicians singled out MTBE as the villain
of the piece.
Other studies
about the same time showed leaks from oil industry installations such as
gasoline stations into aquifers that were used for the abstraction of drinking
water. California
relies heavily on shallow boreholes for its water, which are often sunk into
permeable alluvial deposits that are easily contaminated by leaks from installations
at ground level. Fears about MTBE
contamination were hardly allayed by reports purporting to demonstrate that the oxygenate was carcinogenic.
Pressures for a
state-wide ban on MTBE mounted and a law was passed by the state’s legislature
to implement this. One of California’s
senators began to press the US Congress for federal legislation on MTBE.
As has happened
more than a decade earlier, where California
led, other states followed: New York
and Connecticut opted to ban MTBE
from the beginning of 2004, the same date chosen by California
(see ‘The Month in Brief’, January
2004). Another 14 announced bans of
their own covering the period up to 2006.
Some states began to file law suits against manufacturers of MTBE for
contamination allegedly caused by MTBE.
As a result of
the controversy surrounding MTBE over the last few years and the growing number
of prohibitions on its use, US
consumption has fallen sharply. Between
1999 and 2003, demand in the whole of the USA
declined by 31%, while that in California
fell by more then two-thirds (see
Table B). The ban in California,
New York and Connecticut
will reduce the consumption of MTBE by a further 65,000 bpd in 2004.
The fall in MTBE
use has been accompanied by the announcement of MTBE plant closures, including
two in Texas and a third in Wyoming,
which will remove some 32,000 bpd from the USA’s
total capacity of nearly 260,000 bpd.
Other plant closures are inevitable, not only in the USA
but in exporting countries across the world.
Table B
USA: MTBE
consumption, 1999 v 2003
|
Area
|
1999
|
2003*
|
Change
|
|
|
(th bpd)
|
|
California
|
100
|
30
|
(70)
|
|
Others
|
205
|
180
|
(25)
|
|
Total USA
|
305
|
210
|
(95)
|
* estimate
Source: US
Department of Energy
Replacing MTBE
In most instances, MTBE is being replaced in gasoline by
ethanol made from biomass. The use of
ethanol has been heavily promoted by political and industrial interests from
the US Corn Belt states and is also supported by those wanting to increase the
role of renewable energy in US
consumption. An extensive programme of
ethanol plant construction is under way, principally in the corn-growing states
of Iowa, Kansas,
Nebraska and South
Dakota. US
consumption in 2003 amounted to about 175,000 bpd, compared with a
domestic production capacity of around 200,000 bpd. A further 35,000 bpd of ethanol capacity
is planned for 2004.
Not everyone,
however, agrees that ethanol is the answer to the removal of MTBE. Ethanol’s critics charge that its
manufacturing process is energy intensive, involving as it does,
evaporation and drying of wet grains. Some
opponents go further and claim that the use of ethanol in gasoline leads to
increased emissions of oxides of nitrogen and volatile organic compounds,
compared with MTBE, citing evidence from southern California
where ethanol is already in use. Ethanol
is not as easy to handle as MTBE, either.
It requires dedicated transport and storage to prevent it from coming
into contact with water, since even very small amounts of water contaminate
ethanol. Others oppose the increased use
of ethanol on the grounds that it requires a government subsidy.
Some oil
industry groups say the problem is not one of replacing MTBE with another
oxygenate but with the whole idea of adding oxygen to gasoline in the first
place. Studies quoted by CARB show that
some gasolines burn more efficiently without the
addition of oxygen. There is a growing
view in some quarters that the government should set the emission standards to
be met by gasoline and then leave the refinery industry to decide for itself
how to meet them.
One problem that
the removal of MTBE does cause, however, is a lowering of the octane rating of
the resulting gasoline blend. One way to
boost octane levels if ethanol is not to be used would be to add more
aromatics, which are a common by-product of refining and petrochemical operations. Aromatics, though, produce more pollutants in
vehicle exhausts and have been identified as carcinogenic in certain
concentrations.
The other main
non-oxygenate option is to use more alkylate in the manufacture
of gasoline. Alkylate
is already an important component in US
gasoline. US
refiners have some 1.1 mn bpd of alkylation capacity out of a world
total of 1.9 mn bpd. Apart
from improving octane levels, alkylate has the
further advantage of being less volatile than many gasoline components, thus
keeping alkylated gasoline within federal limits for
vapour pressure. Most US alkylate is produced in the Gulf
Coast region. It is doubtful whether there is sufficient
spare capacity there to replace MTBE in both California
and in New York and Connecticut. Given the logistics of supply, most of the
Gulf’s spare production is likely to head north-eastwards.
Reducing sulphur
The removal and replacement of MTBE is not the only
challenge facing US refiners in 2004.
Under a set of proposals known as Tier II, they are obliged to reduce
the sulphur content of their gasoline from the start of this year as well. Tier II requires refiners to limit sulphur to
120 parts per million (ppm) compared with last year’s ceiling of
500 ppm. The same standard will
apply to gasoline imports. A few, mainly
small refiners will be allowed to produce gasoline up to a limit of
300 ppm, but the overwhelming majority of US gasoline will have to meet
the lower limit.
Not all foreign
suppliers will be able to meet the new sulphur specs without changes to their
crude slates. Some Latin American and
European refiners may have to switch to crudes that are lower in sulphur, as
may some US
refiners as well. This could mean a cut
in demand for sour crudes from Canada,
Mexico, Venezuela
and the Persian Gulf and the corresponding rise in the
premium paid for sweet crudes such as those from West Africa
and the North Sea.
The same considerations apply to refinery feedstocks such as vacuum gasoil
(VGO), which are cracked to produce gasoline.
Late last year, as refiners switched to making low sulphur gasoline the
premium in the US Gulf for low sulphur VGO widened from around 80 cents a
barrel to nearly $3.00.
Gasoline markets
themselves are bound to become fragmented as US
states adopt different specifications.
This can cause problems during temporary shortages of gasoline in some
areas, owing to the difficulty of finding product of the right specification
from neighbouring states where different rules apply. Futures trading is
also affected. Nymex has been obliged to
introduce a new contract based on the New York
and Connecticut grades containing
ethanol, after trading in its standard, non-ethanol contract declined
sharply. Two other futures contracts are
due to be launched in response to the change in gasoline specifications. The New York Board of Trade announced the
introduction of an ethanol contract in May, while the Chicago Board of Trade
said it would have one ready by the end of the year.
The USA
suffered its highest monthly total of casualties in Iraq
during April as the security situation began to spiral out of control. Middle Eastern worries and high US
gasoline demand pushed oil prices to their highest level since shortly after Iraq’s
invasion of Kuwait
in August 1990, as WTI hit $40.
Insurgents targeted several oil installations in Iraq
including the Basrah Oil Terminal and the nearby offshore terminal at Khor
al-Amaya. Exports to Ceyhan in Turkey
resumed following damage to the pipeline, only to be suspended in late April
for what were described as “technical reasons”.
The Iraqi Governing Council, the US Congress and the United Nations
began investigations into the alleged bribery and corruption surrounding
payments made in connexion with the UN’s ‘oil-for-food’ deal under which Saddam
Hussain’s government sold its oil between 1996 and
2003.
Saudi
Arabia made a curious offer to the USA
to build two new refineries there.
Planning regulations make it virtually impossible for anyone to build a new
US refinery. The Saudis’ main aim was to divert criticism
for high oil prices away from OPEC and towards the USA, where gasoline prices
are soaring amid a shortage of refining capacity and increasing demand (see ‘Focus’). Saudi Arabia
meanwhile has agreed to raise crude oil deliveries to East Asia
in an attempt to curb price increases there.
Saudi export volumes will nevertheless be below those contracted for by
Asian buyers. Terrorists killed six
people in an attack on the Saudi Aramco-ExxonMobil refinery complex at Yanbu.
Some members
want OPEC to raise its oil price target above the present $22-28 range (see ‘Looking Ahead’). Iraq
is trying to reduce the volumes of its crude sold to traders, preferring to
sell directly to refiners instead. US
refiners are showing interest in a blend of Basrah Light crude and Ecuador’s
Napo being made available at
storage facilities in Panama. The new blend is said to produce a high quality asphalt.
Russia’s
Yukos has agreed to more than double deliveries of crude oil by rail to China
this year. Volumes have been set at
180,000 bpd. Sinochem is to buy the
bankrupt 270,000 bpd Inchon
refinery in South Korea. The Chinese oil trader says it will process
its own crude there for export to China.
Shell’s troubles
have continued with the publication of an e-mail from its former head of
exploration, Walter van de Vijver, saying he was
“becoming sick and tired about lying about the extent of our reserves.” The company has also announced it is to sell
its retail network in Spain
and Portugal. Italy’s
ENI is also to give up petroleum marketing, along with refining, in Portugal,
as part of a deal enabling it to increase its role in the country’s gas
business. ENI is to take a 49%
shareholding in the national utility, Gas de Portugal. The Czech government has approved a
$476 mn bid by Poland’s
PKN Orlen for the 63% state-owned downstream company Unipetrol (see ‘Focus’, November 2003). Another Polish firm, Lotos, is to take
minority stakes in three Polish refineries owned by Nafta
Polska.
A subsidiary of US
utility Reliant Resources has been charged with manipulating electricity prices
in California by deliberately
taking generating plants off-line in order to drive up power prices. The indictment refers to events alleged to
have happened in 2000 when the state was plagued by power blackouts and
electricity prices soared (see ‘Gas
and Power’, August 2002). The state is
claiming $9 bn in compensation from various electricity companies for what
it claims was excessive overpricing.
Other companies charged include Enron.
Qatar Petroleum,
Sasol and ChevronTexaco have announced plans for
196,000 bpd of new gas-to-liquids capacity in the emirate based on the
expansion of an existing project and the building of a new one (see ‘Focus’, October 2003). The Philippines
has agreed to build the country’s first LNG terminal, to be sited at Mariveles in Bataan
Province, alongside a 1.2 GW
power station, with completion scheduled for 2007. Romania
is planning to extend its underground gas storage network. France’s
last coal mine has closed.
Price controls imposed by the Argentinian government on gas
producers have led to widespread shortages.
Wellhead prices were frozen in January 2002 as part of a series of
measures designed to deal with Argentina’s
economic crisis, but the price controls have only served to boost demand for
gas, creating nationwide shortages and forcing the country to import heavy fuel
oil in order to keep power stations running.
The government finally agreed to a 37% increase in prices for producers
from 1 May, but this is unlikely to do much to relieve the shortage of supply
as Argentina
goes into the peak period of winter demand.
Gas crisis
The freeze on gas prices helped to reverse a sharp fall in
domestic consumption at the start of the decade. Last year, demand rose by 10% to
3 bn cfd, and demand has continued to increase during 2004, with a
further rise of 10% forecast this year.
The largest increase in gas consumption has occurred in the power
sector, with a rise in gas use in electricity generation of nearly 13% between
2002 and 2003.
The power sector
is now experiencing shortages of gas as electricity demand approaches its
seasonal winter peak. This year, the situation
is made worse by a shortage of hydro-electric power, following several months
of low rainfall. Many hydro-electric
plants are reported operating at less than half their installed capacity. Hydro-electricity usually provides about 40%
of the country’s power.
In an attempt to
conserve gas supplies, Argentina
has cut its exports to Chile
from their contracted level of about 610 mn cfd to
525 mn cfd, forcing generators to import coal and oil in order to
keep their stations running. Large
consumers inside Argentina
have also had their supplies cut.
Power shortages
Among the large consumers experiencing supply cuts have been
several Argentinian generators. They
have responded by switching fuels and reducing electricity exports, whilst the
government has begun negotiations with Brazil
for the import of electricity. It has
also asked Bolivia
to supply 140 mn cfd of natural gas for six months from the start of
May. Bolivia
formerly supplied gas from fields operated by Repsol-YPF via a pipeline across
the Andes.
Venezuela
has agreed to provide up to 4.5 mn bbl of heavy fuel oil and
1.6 mn bbl of gasoil in return for agricultural produce and
steel. The fuel oil, however, has a
higher sulphur and metals’ content that that permitted by Argentina’s
electricity regulator. This has forced
power companies to turn to refiners in Brazil,
the Caribbean and the US Gulf for supplies that meet
official specifications. Some fuel oil
cargoes have been sought from as far away as Europe.
As a further
measure to conserve gas supplies, Argentinian generators have scaled back
exports of electricity to Uruguay,
which relies on Argentina
for nearly 20% of its supply. Uruguay
has been forced to bring mothballed oil-fired capacity back into operation and
has also approached Paraguay
and Brazil for
emergency electricity supplies.
Argentina
is asking Brazil
to supply it with electricity, using the 500 MW interconnexion
linking southern Brazil
with the Argentinian province of Corrientes (see ‘Gas and Power’, March 2004). Brazil,
however, may not be able to supply the full amount requested by Argentina. Less than three years ago, Argentina
was exporting electricity to Brazil.
Reviving the gas industry
Argentina’s
gas production has risen steadily in recent years (see Table 5.2a), but investment has been badly hit by the freeze on
wholesale prices, threatening future levels of growth. The government has accused foreign gas
producers of deliberately creating shortages in an attempt to force it to agree
to higher prices.
It is not only
the producers, however, that have been suffering from low prices. Gas distribution companies have also been
unable to raise their tariffs, and several have run up large debts as a
result. The Buenos
Aires distributor, Metrogas,
was forced to default on a debt of more than $400 mn. Gas tariffs were last raised in May
2002. An application for a further rise
by distributors in December of that year was blocked by the courts.
Argentina
has ambitious plans to increase gas production, as well as to raise the use of
gas in power generation (see ‘Gas and
Power’, September 2002). Output is
slated to rise from 5 bn cfd to 6 bn cfd between now and
2010, while consumption is forecast to increase by nearly a third to
4.5 bn cfd. Low wellhead
prices could slow down any expansion in production, but a more serious problem
may well be the state of the country’s gas transmission system, which is
already under strain from rising production.
Unless this is expanded within the next two years or so, Argentina
will not be able to go on increasing its production of natural gas
Geopolitical complications
Argentina
may well find that it has less gas available in future than currently
anticipated. Given the recent response
to gas shortages, the place most likely to be affected by problems in Argentina
is Chile.
Chile
has built several gas-fired power stations based on the long term import of gas
from the Argentine. More than a quarter
of its generating capacity now consists of combined-cycle gas turbine stations. Chile’s
only real alternative to Argentina
as a source of supply is Bolivia,
but a territorial dispute dating back to a nineteenth century war prevents any
deal between the two countries.
Following the war, Bolivia
lost its access to the sea and the government has demanded the right of access
to the Pacific Ocean via Chile
before it will agree to sell gas to Chile. It has even been reluctant to sell gas to the
Argentinians for fear they will re-sell it to Chile
and has written into its contract a clause prohibiting Argentina
from raising its exports to Chile
as long as it is importing gas from Bolivia.
Uruguay,
on the other hand, may try and replace its lost electricity imports from Argentina
by building gas-fired power stations of its own and then fuelling them with gas
imported from Bolivia. Both Uruguay
and Chile look
like having to pay more for their gas and power in future as a result of this
year’s crisis in Argentina.
The weakness of the US dollar has revived the discussion
inside OPEC and elsewhere over whether to continue the international pricing of
oil in the American currency unit or whether instead to select another unit of
account. The alternative at present is
the euro which, after a shaky start in the international market has steadily
increased in value against the US
currency.
The debate about
changing currency units is not a recent one.
As far back as the 1970s, some OPEC members were considering a switch to
a basket of currencies, such as the International Monetary Fund’s Special Drawing
Rights (SDR), during an earlier period of dollar weakness. More recently, the Iraqi president, Saddam
Hussain, began to price his oil exports in euros, though this was meant as a
gesture of political defiance aimed at the US
government rather than as a measure designed to improve Iraq’s
economic circumstances.
OPEC worries
Despite a formal proposal by OPEC in 1975 to adopt SDR as a
unit of account for the pricing of crude oil, the oil producers stuck with the
US dollar, though from time to time they tried to compensate for any
significant decline in the purchasing power of the US
currency by raising the dollar price of their exports. In 1981, however, OPEC members became
concerned principally with competing with each other for market share in an oil market that
was in sharp decline. The purchasing
power of the US dollar ceased to have much relevance when OPEC members were
obliged to take whatever price the market dictated in an era of oversupply and
global recession.
This period came
to an end in 1986, when OPEC ministers introduced the concept of the ‘reference
price’: a target price for a basket made up of the principal OPEC crudes,
expressed in US dollars. The first such
price was $18 a barrel, which was raised to $21 some four years later, before
being expressed as a range of $22 to $28 a barrel in March 2000.
At various
times, individual OPEC members tried to persuade some of their customers to pay
in currencies other than the dollar, notably the German mark and the Japanese
yen. There was little enthusiasm for
such a move amongst importing countries, which preferred where possible to take
advantage of their own currencies’ strength in order to reduce their import
bills for oil.
Pricing the basket
Dollar weakness has returned since late 2000, but this time,
oil prices are rising sharply. In early
May 2004, crude oil prices were at their highest level since just after Iraq’s
invasion of Kuwait
in August 1990. This has nevertheless
not stopped some producers from calling for oil’s link to the US dollar to be
reconsidered.
Last December,
OPEC’s Secretary General, Alvaro Silva said that the organization was
evaluating the use of either the euro or a basket of currencies as a way of
compensating for the dollar’s decline. The
call for a fresh look at oil pricing has also come from the Russian President,
Vladimir Putin, who told the German Chancellor, Gerhard Schröder,
that Russia
“might consider” pricing its exports in euros.
Since then, EU officials have indicated that they would not entirely be
averse to such a move, and the matter has been discussed further at a meeting
between the Russian Deputy Prime Minister and members of the European
Commission’s Directorate-General of Energy and Transport.
Mr Putin’s
proposal appears to apply principally to Russian crude oil exported by pipeline
to Western Europe, raising the spectre of oil pricing by
Russia in more
than one currency. Such a step appears
unlikely and in any case raises the question of whether the Russians might
subsequently request a return to the dollar if the euro were to weaken against
the US
currency.
Nor is OPEC
likely to switch to the euro or a basket of currencies in the near future. While Libya
and Nigeria
have complained that the weak dollar undervalues their exports, there has been
no serious call for it to be replaced as the unit of account for oil pricing,
and the issue was not formally raised at the group’s ministerial meeting at Algiers
on 10 February this year. Instead there
have been calls for a straightforward raising of the
target price range in US dollar terms.
The dollar is likely
to remain entrenched as the pricing unit for oil for a number of important
reasons. In the first place, the world’s
exports are mainly priced in relation to a small number of non-OPEC crudes such
as Brent/BFO, West Texas Intermediate, Dubai, Oman
and Tapis, all of which are priced in dollars and where there are no serious
proposals to alter the unit of pricing.
Secondly,
hedging of oil prices takes place in dollars in the world’s principal forward,
futures and other derivative markets. A
switch to another currency would greatly increase the basis-risk for traders
trying to protect their margins. In many
cases, it would make little sense for either buyers or sellers to abandon the
dollar. OPEC sales to the USA
are an obvious example, but the same applies almost equally to the crude oil
trade between OPEC and East Asia. This leaves the trade between OPEC and the
euro zone, but the use of a separate currency here would simply serve to fragment
a more or less integrated world oil market and make oil transfers between world
regions less efficient.