The lifting of United Nations’ sanctions on Iraq should revive interest in oil and gas developments there. Iraq could prove more enticing than any other Middle Eastern country, given the enormous reserves it undoubtedly possesses, tempting international oil companies away from other projects in the region. One country that could be particularly affected is Iran, which is already struggling to attract private participation in some of its oil and gas projects.
Iran’s situation could become worse if the USA were actively to promote Iraq as a rival upstream prospect to Iran. Many in Washington might welcome the opportunity to punish Iran for its previous hostility to the USA and its alleged support for international terrorism. Funnelling international investment away from Iran might also be seen as bringing about the regime change in Tehran that US defence secretary Donald Rumsfeld appears to want. Iran’s popularity in Washington has hardly been high since President George W. Bush enrolled it in his ‘axis of evil’. More recently, Tehran has come under renewed criticism for its nuclear power programme, which some in the US administration see as having a military dimension. With its large reserves of oil and natural gas, Iran has much to lose from any falling-out with Washington.
Iran has the fifth-largest proven oil reserves in the world and the second-largest gas reserves. Despite this, it is struggling to increase its production of oil and is a net importer of gas. The Iranian economy is dominated by the state sector, which increased substantially following the revolution of 1979. Successive governments have struggled to finance ambitious economic development programmes since then, particularly during times of low oil prices. Iran has more or less consistently restricted oil production in support of high oil prices and has seen its market share diminish as a result.
With output at its peak at 6.0 mn bpd in 1974, Iran had a 20% share of OPEC’s crude oil production. During the first quarter of 2003, with production averaging 3.7 mn bpd, Iran’s share of OPEC’s production was down to 14%. This proportion is set to decline further once Iraq’s output rises above its pre-war levels. Iran views such a development with alarm, and the oil minister, Bijan Zanganeh, has called for Iran’s production capacity to be increased from 4 mn bpd to 5 mn bpd by 2005.
This is easier said than done. Iran is heavily dependent on fields that are mature or in decline. Many date back to the 1960s and before, and several important fields have suffered from neglect as a result of oil policies pursued after the 1979 revolution, when output was reduced and secondary recovery was cut back, causing reservoir pressures to fall and the consequent permanent loss of billions of barrels of reserves.
| Table A | |
| Iran: oil and gas balance, 2002 | |
| Oil* | (mn bpd) |
| Production | 3.6 |
| Consumption | 1.2 |
| Net exports | 2.4 |
| Gas | (bn cfd) |
| Production | 5.8 |
| Consumption | 6.2 |
| Net imports | 0.4 |
| * including NGL | |
A problem in many fields has been water encroachment, which reduces output capacity. Other fields have, by contrast, been overproduced, in an attempt to compensate for falling output elsewhere. This can give only temporary relief and eventually these fields decline as well, often rapidly. Iran claimed recoverable oil reserves of 90 bn bbl in 2002; but this figure is almost certainly an over-estimate. The actual figure may well be below 80 mn bbl.
Oil production is primarily the responsibility of the state-owned National Iranian Oil Company (NIOC {http://www.nioc.org/}), but NIOC lacks the resources to fund and develop all the fields required to raise Iranian output as planned. The government, however, has often been reluctant to allow private capital into the oil sector and some of the contractual arrangements for oil production have proved problematic. The oil ministry has sought to attract foreign oil companies but has met with limited success. US companies have been prohibited form working in Iran under the 1996 Iran-Libya Sanctions Act {http://www.eia.doe.gov/emeu/cabs/sanction.html}, and Washington originally sought to discourage non-US firms from going to Iran through the threat of sanctions against them. The Iranians too have put obstacles in the way of foreign investors. The politically important clerical faction has pressurized the ministry to award oil field projects to Iranian companies, some of which do not have the resources to undertake complex upstream developments. Conservative clerics have also expressed strong opposition to buy-back deals, which form a major part of the ministry’s attempts to bring in outside finance and expertise.
Buy-back contracts have appeared in several forms but, in essence, they require the contractors to fund the development of the oil or gas field in return for an agreed entitlement to the output once the field is commissioned. Under the deals, the contractors can recover costs plus a certain margin. There is no guaranteed rate of return and cost overruns must be met by the contractor unless NIOC agrees subsequently to raise the cost-recovery element. The fields offered under buy-back contracts have been attractive geologically, but foreign companies have complained that contract terms are not flexible enough to allow for unexpected problems. Some contracts have been criticized as requiring work to be done in an unrealistically short time, and there is constant clerical pressure on the oil ministry to make contract terms less attractive to foreign companies, or to abandon buy-back deals altogether. Despite this, a number of gas deals have been successfully concluded with outside firms covering the giant South Pars field (see Table B). Oil developments, though, remain a problem.
The Iranian government is particularly keen to develop fields that lie across international boundaries. Tehran fears that some of its neighbours may develop their portions of such shared fields before Iran has begun its own developments there. Shared fields are not necessarily the most attractive geologically, and many foreign firms are nervous about the possibility of future boundary disputes that might affect their title to any oil produced.
One such field is Azadegan, which lies close to the border with Iraq. Tehran fears that the structure will have a high priority with the new Iraqi regime, which it expects Washington will press to increase production capacity as rapidly as possible. Mr Zanganeh says he believes the USA wants Iraq to raise capacity by 4.0 mn bpd to 6.5 mn bpd.
Azadegan’s structure, however, has not yet been fully delineated. It is not even confirmed if part of it does underlie Iraq. Moreover, the Iranian government has not awarded a contract for the field’s development, or even decided whether to develop the field as a single unit or to split it into two contract areas. At present, the Iranians are considering a bid from a Japanese consortium, led by Inpex. The Japanese are thought to be nervous about working on the part nearest the Iraqi border. They have also been unable to agree production targets for the field. The Iranians tend to be over-optimistic when it comes to setting output levels. In the case of Azadegan, they are proposing an ambitious 0.7 mn bpd.
Faced with so many potential contractual difficulties in Iran, international oil companies may well turn their attentions to Iraq, assuming that attractive terms are offered there. Iran could, in turn, find it impossible to raise its own output capacity to the planned 5 mn bpd mark. It is more likely, in fact, that crude oil production capacity will decline over the next few years, leaving Iran increasingly dependent on condensate produced from new gas fields to keep its total liquids’ capacity in the region of the present level of 4 mn bpd.
Stagnant output levels will mean reduced exports as Iran’s oil consumption continues to rise. Following a number of years in which consumption rose by very little, Iran is now facing surging demand for refined products, which are sold at prices well below world market levels. Gasoline demand, in particular, is growing at over 10% a year, and is now running at nearly 315,000 bpd, making up around 26% of domestic product demand. Iran now has to import up to 100,000 bpd of gasoline to satisfy domestic demand. Without both curbs on demand and greater incentives for oil production, Iran’s net exports could be as low as 1.5 mn bpd within about five years.
After decades of neglecting its gas industry, Iran is trying to raise production substantially. Despite enormous reserves, amounting to 812 trillion cubic feet (tcf), second only to those of Russia, Iran is only a modest producer and a net importer (see Table A). There is a small export trade by pipeline to Turkey, but volumes have turned out to be lower than expected (see ‘Gas and Power’, January 2003). Variable amounts are imported from Turkmenistan.
Iran has ambitions to be a major exporter of gas. The pipeline to Turkey was meant to be the first stage of a trunk-line linking Iran with Western Europe (see ‘Focus’, July 2002). The Iranians hoped that Turkmenistan would export gas via the same pipeline, making the project more attractive to international investors, but the USA put considerable pressure on Turkmenistan not to cooperate with Iran in such a project. Iran is therefore concentrating its efforts on liquefied natural gas (LNG) exports from the Persian Gulf instead.
Tehran’s LNG plans have nevertheless also hit snags. Part of the problem is that Iran’s plans have been seen by potential investors as wildly overoptimistic. NIOC was originally proposing four separate projects capable of exporting up to 5.3 bn cfd of LNG: far too much given the likely competition from existing suppliers like Qatar and Oman, and new ones such as Egypt. NIOC is now thinking in terms of about 0.7 bn cfd initially, with perhaps a doubling of this quantity if sufficient off-takers can be found. The Iranians want exports to begin in 2008, but 2010 may turn out to be a more realistic start-up date.
| Table B | ||
| South Pars: development programme | ||
| South Pars is to be developed in 25 phases, as below: | ||
| Phase | Status | Projected output |
| 1 | Delayed; on-stream 2003/4 | 1.0 bn cfd 40 000 bpd |
| 2–3 | On-stream 2002. Condensate output 90–120,000 bpd | 2.0 bn cfd 80 000 bpd |
| 4–5 | On-stream 2005 | 2.0 bn cfd |
| 6–8 | On-stream 2005 | 2.6 bn cfd 120 000 bpd |
| 9–10 | On-stream 2007 | 2.0 bn cfd 80 000 bpd |
| 11 | First LNG Project; on-stream 2008–10 | 0.7–1.4 bn cfd |
| 12–13 | Originally LNG projects; status now uncertain | 2.1 bn cfd |
| 14 | Gas-to-liquids development | 70 000 bpd* |
| 15–16 | Tenders invited | 2.0 bn cfd 50 000 bpd |
| 17–25 | No timetable agreed | — |
| * Liquids volumes refer to condensate, except for Phase 14, which is GTL | ||
Iranian gas plans centre on the South Pars field, which contains an estimated 300 tcf of gas, though precise reserve levels have yet to be ascertained. The field is to be developed in 25 phases. Production from the first section to be developed (Phases 2–3) began in 2002 and has proved higher than expected. It was developed by TotalFinaElf, Gazprom, and Petronas under a buy-back contract, and has been handed over to the South Pars Gas Co, a subsidiary of NIOC, under the terms of the deal. Contractors involved with other phases include ENI, Hyundai, Samsung, and several Iranian firms. In most cases the developments involve the production of condensate as well as gas, together with liquefied petroleum gas in some instances. The next tranches of new production are due on-stream in 2005 (see Table B).
Iran’s oil and gas plans have attracted considerable US opposition, even though threats of sanctions against foreign investors were eventually withdrawn. The latest bone of contention is Iran’s plans for nuclear power. The Iranians are building a 1GW nuclear station with Russian help at Bushehr. The plant is due on-line in 2004, and another one, also of 1 GW, is now on the drawing-board. Further units have been considered, both at Bushshr and at Ahvaz. Washington says that Iran does not need any nuclear capacity, owing to its extensive gas deposits, and accuses Tehran of using nuclear power as a cover for weapons’ production. Tehran denies the charge.
None of this, however, is calculated to improve relations between the two governments. US advocates of regime change in Tehran claim that the Bushehr project merely serves to illustrate the duplicity of the so-called ‘reformist’ government in Iran and are calling on the Bush Administration to break diplomatic ties and impose economic sanctions. Even without all this, Iran has considerable difficulties in attracting investors. Some foreign companies are already nervous of the influence of militant clerics on Iran’s oil and gas industries: political tension with Washington would alarm them still further.
Recently, Iran made a further move designed to raise hackles in the US capital. The government is secretly promoting the idea of building an oil pipeline between Kazakhstan and Iran. The Iranians want to increase their oil trade links with their Caspian neighbours. Their immediate aim is to obtain supplies for the 225,000bpd Tehran refinery. Iran has begun importing about 50,000 of Kazakh, Turkmen, and Russian oil since last year, to which a further 21,000 bpd of Kazakh Kumkol crude will be added in August. The oil is supplied by rail and ship at present. Now, Iran wants to increase import volumes to around 500,000 bpd using a purpose-built pipeline serving Kazakhstan and Turkmenistan.
Iran exports similar quantities of its own crude from the Persian Gulf on behalf of its Caspian suppliers. The arrangement has the great advantage for NIOC of allowing it to maintain existing export levels of Iranian crude to Asia, thus protecting its market share in its key markets. The USA has consistently opposed the idea of Iran’s becoming a transit route for Caspian crude and is promoting a much larger pipeline project of its own from the Caspian to the Turkish Mediterranean port of Ceyhan (see ‘Focus’, July 2002). Russia also has a programme to develop a pipeline route along the northern edge of the Caspian to the Russian Black Sea port of Novorossiysk. There is unlikely to be room for all three projects, providing yet another cause of friction between Tehran and the Bush Administration.
Gas consumption in Latin America is rising at more than 5% a year: nearly twice the rate of energy consumption as a whole. After a slow start, demand for gas for electricity generation is rising rapidly and is expected to grow by nearly 10% a year during the remainder of the decade. The region accounts for about 5% of world production and roughly the same proportion of world demand. There is a small net export of gas and the region possesses around 5% of the world’s proven reserves of natural gas (see Table C).
Reserves, however, are not evenly distributed, being found mainly in the north: in Venezuela and Mexico which, between them, account for 63% of the region’s proven reserves. Many Latin American countries rely on imports from their neighbours, but the lack of a trans-continental transmission system limits market growth.
The lack of a suitable infrastructure has hindered the development of residential and commercial markets for gas in Latin America. The main demand comes from industry, which accounts for nearly one-third of total consumption. Electricity demand is mainly met by hydroelectric power, but a recent decline in rainfall totals has caused Brazil, Argentina, and Chile to reassess their reliance on hydroelectricity and to turn to gas instead. The electricity sector accounts for about a quarter of gas demand at present, but this proportion is expected more or less to double by 2025.
Table C |
|
Latin America/Caribbean: gas balance, 2002 |
|
| Reserves: | 282 tcf |
| Production: | 15.2 bn cfd |
| Consumption: | 13.3 bn cfd |
| Industrial | 4.2 bn cfd |
| Power generation | 3.3 bn cfd |
| Net exports/losses: | 1.9 bn cfd |
Mexico and Argentina are the region’s largest gas consumers, with about 3.3 bn cfd each. Argentina has the best national infrastructure in the region and has a higher proportion of residential and commercial demand than most Latin American countries. Production is sufficient to supply the domestic market and to provide a surplus of 0.5 bn cfd for export, principally to Chile.
Mexico, on the other hand, has a poorly developed infrastructure and has experienced several problems in developing its gas production. State oil company Pemex lacks the resources to develop new gas production, but the government is unwilling to open the upstream sector fully to foreign oil and gas companies (see ‘Gas and Power’, March 2003). Gas demand is being driven by electricity, but any increase in gas consumption will have to come from imports from the USA, and these are now close to the maximum that Mexico’s import infrastructure can handle.
The state power company, Comisión Federal de Electricidad (CFE) is seeking expressions of interest from potential suppliers of liquefied natural gas (LNG), but so far, no import terminals have been built. Sempra Energy plans a 1 bn cfd terminal at Ensenada, in Baja California, but does not yet have a supply deal. Some of the gas may, in any case, end up being exported to the USA rather than being used to meet Mexican demand.
One of the potential suppliers that Sempra has approached is Bolivia, which plans to pipe gas to the Pacific for export as LNG. Bolivia is potentially an important producer, but its domestic market is small, leaving it with a surplus, and one that is likely to grow. Gas is currently exported to Brazil, but Brazil’s demand for imports, especially for use in power stations, is failing to grow as rapidly as anticipated, leaving the export pipeline operating at well below capacity. LNG exports are seen as essential if exploration for gas is to be revived in Bolivia, but the land-locked Bolivians have been unable to find a suitable site for an export terminal. Plans for one in Chile have become mired in a boundary dispute between the two countries dating from the 19th century.
Bolivia’s only short-term solution is to resolve its supply dispute with Brazil; but here, again, the omens are not good. Recession in Brazil has halted the recent rise in gas demand and gas-fired power developments have been cut back as a result. Brazilian imports, however, are governed by a take-or-pay agreement with Bolivia: currently for a minimum quantity of 14 mn cfd, rising to 18 mn cfd next year. Brazil is refusing to take more than 11 mn cfd unless the price of the gas is reduced, which Bolivia has so far refused to do. Meanwhile, the Repsol-YPF consortium, which is trying to develop the LNG option, has announced that it is reducing its exploration efforts in Bolivia.
Bolivia’s latest response is to propose a joint LNG export scheme with Peru using gas from Repsol-YPF’s Margarita field in Bolivia and Peru’s Camisea field which, like Margarita, requires the construction of a pipeline from the Andes to the Pacific coast. Camisea’s gas is initially earmarked for power generation, but the field’s owners want to export LNG to the USA eventually. A better option altogether might be gas-to-liquids (GTL). Such plants might well be able to supply Bolivia with diesel fuel, replacing costly imports. GTL, however, would almost certainly require the gas feedstocks to be provided at low cost, which is also the issue at the core of the current dispute with Brazil.
Brazil is now looking elsewhere for supplies of gas. One possible source is Venezuela. The two countries have recently agreed to cooperate in a series of oil and gas ventures that could see Brazilian imports from Venezuela or Venezuelan involvement in gas production inside Brazil. Venezuela wants to become a major exporter of LNG. There are plans for a 0.8 bn cfd terminal at Mariscal Sucre, but it is not clear how state-owned Petroleos de Venezuela will be able to finance its 60% share of the project. Venezuela’s neighbour, Trinidad and Tobago. not only exports LNG but has also developed a number of major gas-using industries, including the world’s largest methanol plant. LNG is also emerging as the power generation fuel of choice in some Caribbean islands, including Jamaica and the Dominican Republic.
© Blackwell Publishing Ltd, 2003