A general strike in Venezuela has led to the loss of more than 2 mn bpd from world oil markets and forced crude and product prices up around the globe. Most affected is the United States of America, which faces oil shortages just as Washington was trying to build stocks in advance of a war with Iraq. The strike, which began on 2 December, was originally designed to last only for a few days. Its continuation into January seems to have surprised most oil refiners, who belatedly began a scramble for oil supplies after it became clear the strike was going to be prolonged. The interruption in supplies may help to put energy policy back on Washington’s agenda after a period in which it seemed to have lost much of its urgency.
The strike is part of an attempt to unseat Venezuela’s President, Hugo Chávez. The opposition wants Mr Chávez to hold a referendum on his presidency and resign if defeated. Despite a government pledge that any strike would not be allowed to disrupt oil exports, these have fallen from over 2.4 mn bpd to less than 0.5 mn bpd while supplies to the domestic market have been sharply cut as well. Venezuela, until the strike the world’s fifth-largest exporter of oil, has been forced to import from Brazil and Trinidad and Tobago.
The country most affected internationally by the Venezuelan strike is the USA. Venezuela is the USA’s fourth-largest supplier of crude-oil imports, accounting for just over 13% of the total (see Table A). It is also the fourth-largest supplier of refined products, with around 9% of the USA’s total imports (see Table B), giving it a combined market share of over 12% for total US oil imports.
Table A |
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USA: crude oil imports, January–September 2002 |
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Country |
Volume (th bpd) |
Market share (%) |
| Saudi Arabia | 1 480 | 16.5 |
| Mexico | 1 454 | 16.2 |
| Canada | 1 379 | 15.3 |
| Venezuela | 1 201 | 13.4 |
| Nigeria | 563 | 6.3 |
| Iraq | 483 | 5.4 |
| United Kingdom | 375 | 4.2 |
| Norway | 353 | 3.9 |
| Angola | 315 | 3.5 |
| Colombia | 234 | 2.6 |
| Others | 1 151 | 12.8 |
| Total | 8 988 | 100.0 |
| NB: percentage totals rounded | ||
| Source: US Energy Information Agency (EIA) | ||
The loss of Venezuelan imports pushed the price of the US West Texas Intermediate (WTI) marker crude above $32 a barrel in early January, and other sweet crudes around the world went up in sympathy. North Sea Brent rose above $30 and buyers of crudes from other leading US suppliers, such as West Africa (see Table A), found themselves having to pay a much higher premium than normal for scarce supplies. An undertaking by OPEC to increase production if prices remained above $28 for longer than 20 days helped to slow down the rise in WTI and Brent prices, but OPEC’s pledge does nothing to help refiners in the US Gulf, since any such supplies are several weeks away. A large part of the problem for US refiners is that Venezuela is a short-haul refiner, just a few days distant in terms of tanker voyages.
The Venezuelan strike has also deprived the USA of around 0.2 mn bpd of refined products and petrochemical feedstocks (see Table B). The main products supplied by Venezuela to the USA are motor gasoline and heating oil. US buyers have been forced to obtain replacement supplies from as far away as Singapore, the Persian Gulf, and Russia. The loss of gasoline imports has been compounded by a cessation of Venezuelan exports of feedstocks used to make gasoline, including vacuum gasoil (VGO), which is sold by Venezuelan refineries to US refiners for cracking into gasoline and middle distillate. Prices for low-sulphur VGO even rose above the price of the products made from it in US Gulf markets at the start of the year.
Table B |
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USA: refined product and feedstock imports, Jan–Sept 2002 |
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Country |
Volume (th bpd) |
Market share (%) |
| Canada | 497 | 21.8 |
| Algeria | 251 | 11.0 |
| US Virgin Islands | 222 | 9.7 |
| Venezuela | 201 | 8.8 |
| Russia | 107 | 4.7 |
| Others | 1 004 | 44.0 |
| Total | 2 282 | 100.0 |
| NB: percentage totals rounded | ||
| Source: EIA | ||
The loss of Venezuelan supplies has also reduced US inventory levels: in some cases to almost precarious levels. Some inventories are close to 20-year lows. Crude stocks at the end of 2002 were 22% down on year-earlier levels, while product stocks declined by 7% over the same period (see Table C). Refinery output, on the other hand, was up by 5%, or 1 mn bpd, to 20 mn bpd.
Table C |
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USA: year-end stock levels, 2001 v. 2002 |
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Stocks |
27 Dec 2002 (mn bbl) |
27 Dec 2001 (mn bbl) |
Change (mn bbl) |
| Crude oil | 278.3 | 312.0 | –33.7 |
| Gasoline | 205.0 | 210.2 | –5.2 |
| Middle dist | 126.8 | 143.6 | –16.8 |
| Other prods | 344.9 | 371.0 | –26.1 |
| Total prods | 676.7 | 724.8 | –48.1 |
| Source: EIA | |||
In addition to the commercial stocks recorded by the EIA, the USA has a Strategic Petroleum Reserve (SPR) of nearly 600 mn bbl, operated by the government (see box). The SPR was established in 1975 to deal with any major interruption to oil supplies, and the government has come under pressure from refiners and consumers to release some of its strategic stocks, which are nearly all in the form of crude oil stored in salt caverns on the US Gulf Coast. The government has continued to increase SPR levels, however, despite the lack of Venezuelan supplies, arguing that it will be needed in the event of a war with Iraq, which could remove a further 2 mn bpd from world oil markets.
The principal impact of the loss of Venezuelan supplies has been in the US Gulf, where refineries have lost around 20% of their normal crude supplies and 40% of their heavy crude. Many Gulf refineries are configured to run on heavy and sour crudes. Some of them are even owned by Petróleos de Venezuela (PdV), the country’s national oil company, through its US subsidiary Citgo. Venezuela purchased the refineries as a way of giving it a captive market for its crudes, particularly its heavier grades. Citgo has already cut runs at the 269,000-bpd Houston refinery in Texas, and in early January announced possible restrictions at its 157,000-bpd Corpus Christi refinery in Texas and at its 321,000-bpd Lake Charles, Louisiana plant.
Some Caribbean refineries supplying the USA have also been badly hit by the Venezuelan strike. The 300,000-bpd Curoil refinery on Curaçao, Netherlands Antilles, which is leased by PdV, was shut down in December as crude supplies ceased. In the US Virgin Islands, the 525,000-bpd St Croix refinery, half-owned with Amerada Hess, lost some 270,000 bpd of Venezuelan crude, though Amerada was able to replace some of this with imports from West Africa and Russia.
These Caribbean refineries, along with some Venezuelan export refineries, are important suppliers of refined products to the USA. Together they supply more than 0.4 mn bpd of products and feedstocks to US markets, primarily in the north-east, where many gasoline and heating oil distributors have supply contracts with PdV. US refiners are not able easily to make up the shortfall since most are operating close to capacity, and even where there is some spare distillation or upgrading capacity, the distribution system, which is also near capacity, often cannot cope either.
Strategic Petroleum Reserve
The SPR was set up under the Energy Policy and Conservation Act of 1975, which describes the SPR’s role as reducing
the vulnerability to economic, national security and foreign policy consequences of supply interruption by discouraging supply disruption as a tool of other nations and by adding to crude oil supplies in the US in the event of a disruption due to either political, military or natural causes.
There is no automatic mechanism to trigger the release of stocks from the SPR, and it tends to be used only as a last resort. The only time it has been used in a national emergency was in 1991 during Operation ‘Desert Storm’ in the Gulf War. Even then, the draw-down amounted to only 17 mn bbl.
Congress ordered some sales in 1996 and afterwards for short term fiscal reasons and to curb a rise in gasoline prices, but these were widely criticized as being politically rather than strategically motivated.
The SPR contains about 600 mn bbl of crude oil and 2 mn bbl of heating oil. The US government wants to raise crude levels to 700 mn bbl.
In May 2001, the National Energy Policy Development Group, under Vice-President Dick Cheney produced a document designed to form the basis of a new US energy policy. The paper concluded that the USA faced a future of energy shortages, supply disruptions, and high prices unless it adopted a series of measures to increase domestic production and slow down the rate at which demand was increasing. In the sphere of oil, the report called for the opening-up of areas currently off-limits to development; the diversification of import sources; higher stock levels; and the expansion of the refining and distribution system. There has been little progress on any of these ideas, however, since the report came out. Supporters of an energy policy are hoping that the problems caused by Venezuela might start the energy debate off once more.
The most controversial proposals of Mr Cheney’s group were to permit oil drilling in environmentally-sensitive areas such as the Arctic National Wildlife Refuge (ANWR) in Alaska, and in offshore areas like California and the Gulf of Mexico. The report claimed around 10 bn bbl was recoverable from ANWR and a further 59 bn bbl from offshore areas. Many Democrats and even some Republicans have declared their opposition to one or more of these proposals and, despite the Republicans having control of both Houses of Congress, there seems little chance of an early resolution to this issue.
Plans to diversify the source of US oil imports rely on some fairly long-term developments such as the production of more oil in the Caspian and Central Asia (see ‘Focus’, July 2002). In the meantime, the USA, for all its worries about dependency on the Middle East, has been stepping up its imports of crude oil from Iraq. During December, the USA imported an estimated 600,000 bpd of crude oil from Iraq: some 50% more than it did between June and November 2002. The sudden surge was partly a result of the loss of Venezuelan supplies, but figures for the first nine months of 2002 show a steady demand for Iraqi crude, which made up more than 5% of total US imports of crude oil (see Table A) despite some efforts by the Bush administration to discourage imports from Iraq last year. Unsurprisingly, perhaps, some commentators have accused the Bush administration of wanting to go to war with Iraq in order to bring Iraq’s production under US control.
The interruption to Venezuelan exports complicates Washington’s war planning by raising the prospect of a world shortfall of more than 4 mn bpd before the end of the first quarter of 2003 in the event of a prolonged strike in Venezuela and a war with Iraq. The USA alone stands to lose some 1.7 mn bpd of crude oil supplies in such an eventuality. While OPEC has indicated it will step up crude production, it will struggle to replace both Iraq and Venezuela. Some producers, including Saudi Arabia and Kuwait, are, in any case, vulnerable to supply disruptions of their own in the event of Iraqi or terrorist attacks on their oil facilities. Such additional oil as they can produce is, in any case, six weeks or more from the main consuming countries. With stocks there low as well, prices look set to soar—even if only for a short time. In these circumstances, the SPR is likely to be of major importance in keeping US markets supplied.
Venezuela: pre-strike oil balance |
|
| (th bpd) | |
Production |
|
| Crude | 2 315 |
| Heavy crude | 350 |
| Gas liquids | 185 |
| Condensate | 150 |
| Total | 3 000 |
| OPEC crude quota | 2 497 |
| Domestic consumption | 540 |
| Total Exports | |
| Crude | 1 760 |
| Products | 700 |
| Total | 2 460 |
Oil from the SPR—or anywhere else—will not relieve the USA’s shortages on its own. Getting the oil to end-users is a major problem given the present overloading of the US oil infrastructure. There is little that can be done about this in the immediate future, but the issue needs to be tackled urgently if the USA is not to be plagued by temporary oil shortages and price spikes over the next few years.
In one sense, the principal US shortage is one of refined products rather than crude oil. The country’s refinery system is running at 100% of nameplate capacity: sometimes even above. Despite an annual rise in refined products consumption over the last ten years of 1.4%, no major new refineries have been built in the USA and capacity has been growing at slightly less than that rate, largely as a result of ‘debottlenecking’ and other improvements at existing refineries. Environmental restrictions on new refinery-building makes it almost impossible to obtain permission for a new, grassroots development. Refinery builders are further deterred by constant changes in product specifications both at the federal and state level which often lead to the development of small and unprofitable markets for niche fuels across the country. Reform of refining legislation nevertheless seems a long way off, and Americans look like having to put up with seasonal and other short-term product shortages for the foreseeable future. As oil consumption continues to grow, these shortages will become endemic and almost permanent.
The oil transport infrastructure is in scarcely any better shape. Most oil pipelines operate at capacity and cannot cope with sudden surges in demand, as for example regularly occurs for heating oil in New England in winter. Crude pipelines are also congested and there are regular price squeezes in the Mid West as a result of congestion in the main crude pipelines from the Gulf Coast to the refineries of the Chicago–Great Lakes area. These push up the price of both WTI and imported crudes, causing crude prices to rise elsewhere in the Atlantic Basin. US pipeline problems are more susceptible to alleviation than those of refining, but congestion nevertheless looks likely to persist for several years. Perhaps the only way the Americans will solve these problems is if they are forced into action by a prolonged and severe shortage of oil.
Faced with rising oil consumption and physical problems in increasing output, Iran is turning increasingly to natural gas to provide it with additional hydrocarbons. More gas is to be used domestically, as well as exported. An important aim of the gas policy is the substitution of gas for oil in the home market in order to allow more oil to be exported. One of the principal areas for substitution will be the electric power sector.
Iran’s proven reserves of 939 trillion cubic feet (tcf) are the second-largest in the world, and account for 16% of the world total. Iran is, however, only the eight-largest gas producer in the world—roughly on a par with the Netherlands—with an output of 6 tn cubic feet a day (cfd). It imports small quantities from Turkmenistan and exports a roughly similar amount to Turkey, though there have been disputes over quantities and other matters.
Iran’s main gas development is the South Pars field in the Persian Gulf. Recoverable reserves have been estimated by the National Iranian Oil Company in the region of 300 tcf, though many outside estimates are smaller. The field is nevertheless of considerable size. Two phases are producing an estimated 2 bn cfd of gas, but there have been delays to other phases. Some 14 development phases have been announced so far. South Pars is also producing some 100,000 bpd of condensate, which is being sent for export.
Much of Iran’s new gas production is at present earmarked for domestic use, though there are also plans for some exports. One of the prime aims is to raise the proportion of electricity generated by gas. Several combined-cycle gas turbine stations are planned in order to bring this about.
Running alongside this plan is a policy to encourage private investment in existing and new gas-fired power stations. Some 2.5 GW of existing capacity, equivalent to 9% of the total installed capacity, could be offered for sale to the private sector by the state utility Tavanir. In addition, seven new power station projects have been offered to private companies by the Iran Power Development Company on a build-operate-transfer (BOT) basis, totalling 6.4 GW of new capacity. Bids have been attracted from several foreign companies, including ABB, Edison, and Sumitomo. A further 5.0 GW is being offered under build-operate-own (BOO) schemes.
More controversially, Iran is also pursuing a programme of nuclear development. Russia’s Atommash is building a 1.0 GW reactor at Bushehr, to be completed in March 2004. The Americans are unhappy, claiming that the project gives Iran access to Russian nuclear weapons’ technology. For its part, Iran has agreed to allow inspections by the International Atomic Energy Agency in order to verify the station’s use as a civilian facility only. It is not yet clear how the spent nuclear fuel will be reprocessed. In principle, the Russians have agreed to do it themselves.
Russia has proposed building another 3.0 GW of nuclear capacity in Iran, partly at Bushehr and partly at Ahwaz, in the west of the country. The US State Department has described such proposals as ‘disturbing’. The Russians also want a role in Iran’s natural gas programme. They have proposed to help build and finance an export pipeline to India and to construct underground gas storage facilities near Tehran and Tabriz.
Iran’s longer-term plans for natural gas include several export schemes targeting both Europe and Asia. Gas is already exported to Turkey, though the Turks have requested a cut in export volumes after their forecasts of demand turned out to be somewhat overoptimistic (see ‘Focus’, July 2002). Iran wants to open up new markets in Europe to stop it having to rely on Turkey, which is being offered more gas than it is likely to be able to use for at least the next decade.
Iranian exports to Europe would have to compete with those from nearby regions, including Turkmenistan, Russia, North Africa, Iraq, and the Arabian peninsula. Asia represents an alternative market, especially India. Russia has proposed to help finance a pipeline from Iran to India, but India has indicated that it is not keen to rely on gas delivered by a pipeline that transits Pakistan.
Another proposal is for Iran to export liquefied natural gas (LNG). Using gas from South Pars, Iran could ship LNG to a variety of destinations, including Europe and India. Three separate proposals have been made involving BP with India’s Reliance, TotalFinaElf with Malaysia’s Petronas, and Shell with Repsol-YPF.
NIOC {http://www.nioc.org/} wants to see LNG exports of about 1.1 bn cfd by 2006 or 2007, but this looks unlikely. In the first place, some parts of the South Pars development are behind schedule. Secondly, LNG exports face just as much competition in Europe and Asia as pipeline exports from Iran. There is, in any case, some uncertainty over how much South Pars gas will be required domestically.
As well as using gas to back-out oil from electricity generation, Iran also has plans to use it to make high quality refined products and petrochemical feedstocks by gas-to-liquids (GTL) technology. Some of the output from GTL plants could be exported. Iran will also extract ethane from Pars gas for ethylene production.
Another idea being touted is the export of natural gas as electricity. The Iranian grid is already linked to the transmission systems of Turkey, Armenia, Azerbaijan, and Turkmenistan, and there are plans for further links to Iraq, the Arabian peninsula, Pakistan, and Afghanistan. Exports, on the other hand, would not necessarily be large, but be based more on exploiting seasonal and even daily differences in demand between Iran and its neighbours.
While oil markets in the Atlantic Basin are well served with reference crudes for use in pricing formulae, those east of Suez are much less well provided for. Large and widely-traded spot markets in Brent and West Texas Intermediate (WTI) have helped establish these two crudes as the basis for most crude oil traded in the Atlantic Basin. Markets east of Suez are dominated by Middle Eastern crudes which are nearly all sold on long term contracts. The principal exception has been Dubai’s Fatah crude, which was once widely traded spot. Falling output, however, threatens to make the market in Fatah crude much less representative of Middle Eastern sour crudes in general. Some futures exchanges have tried, without success, to introduce sour crude contracts to supplement or replace Dubai. Its most likely replacement is Oman crude, but here there are also problems to be overcome.
Dubai has been the principal price reference for Middle Eastern exports since the 1980s. Output was then over 400,000 bpd and a flourishing forward market developed on the back of the physical trade in Dubai. In the early 1990s, however, output began to decline and in 1997 it dipped below 250,000 bpd. Since then, it has continued to fall and is now around 150,000 bpd. Such low volumes make Dubai liable to manipulation by oil traders.
As well as the forward market, there is a swaps market, which is widely used to establish prices for Dubai. These are traded in various sizes and on several different bases. Dubai swaps are usually traded as a spread against other crudes, such as Brent or WTI. The low volume of physical trade in Dubai, however, threatens these derivatives markets as well.
Dubai is used as a reference or ‘marker’ crude in Middle Eastern term contracts amounting to about 11 mn bpd. Buyers, sellers, and traders are all anxious to see a replacement for it, but there is so far no general agreement on what this might be. There is considerable support for the use of Oman crude, but Oman itself is priced in relation to Dubai, spot Oman being quoted as a differential to Dubai crude. Many market participants favour some sort of composite Middle Eastern sour-crude marker based on both crudes. In May 2000, the New York Mercantile Exchange (Nymex) launched a sour-crude futures contract combining Oman and Dubai. Trade never really took off, however, and the contract ceased to trade in 2001.
The Tokyo Commodity Exchange (Tocom) has had somewhat better luck with its sour crude futures contract, again based on Oman and Dubai. It was launched in September 2001 and has recently been trading in volumes of about 2 mn bpd. The Tocom contract, however, has failed to attract much participation from physical traders of Oman and Dubai. Moreover, it is denominated in yen and kilolitres rather than the dollars per barrel used in other crude futures contracts, which limits its international application. Trading volumes, furthermore, are low by the standards of the leading crude futures markets. The Brent contract on London’s International Petroleum Exchange (IPE) trades about 100 mn bpd, while Nymex’s WTI manages nearly double that.
The most recent attempt at an Oman–Dubai futures contract is that of the Singapore Exchange (SGX). Launched in November 2002, SGX’s contract is similar to Tocom’s, except that it is denominated in US dollars per barrel. Trade, however, has been disappointing, falling below 30,000 bpd in December. The precedents for a Singapore-based contract are not that good: a Dubai futures contract introduced by SGX’s predecessor, the Singapore International Monetary Exchange (Simex), folded in the 1990s owing to lack of support.
While futures markets can encourage trade in their underlying physical markets, they cannot replace them. International trade still requires a physical market on which to base its contract pricing. With Dubai in decline, many market participants are now promoting Oman as its replacement.
Oman is roughly similar in quality to Dubai, though Oman is lighter and less sour: 34°API and 0.9% sulphur, versus 31°API; 2.0% sulphur for Dubai. Oman’s production averaged 770,000 bpd in 2002, of which about half is spot traded. The main spot sellers are Shell and TotalFinaElf. The Ministry of Oil and Gas (MOG) is the main term seller and posts its contract price retrospectively once a month. MOG has shown little enthusiasm for Oman’s taking on the role of Dubai in setting Middle Eastern oil prices, but with nearby producers also reluctant to see their crudes become the marker for the rest of the region, Oman may take over by default.
© Blackwell Publishing Ltd, 2003