FOCUS

Saudi terrorist attacks spark world supply fears

The murder and kidnapping of foreign oil workers in Saudi Arabia have awakened fears of an interruption in oil exports from the Kingdom coming, as these events do, on top of earlier attacks on foreigners there. Added to these fears is the further worry that Saudi Arabia is close to its production capacity and thus unable to raise exports to meet the expected rise in world demand. Oil prices have reacted accordingly, pushing futures markets to record levels.

For Saudi officials, the role of the futures markets has been all-important. Many, including oil minister Ali Naimi, blame ‘speculators’ for at least part of the recent rise in prices. Shortages of gasoline in the USA are also seen as a major contributory factor (see ‘Focus’, May 2004). Some Saudis even cite the buying of crude oil by the US government for its Strategic Petroleum Reserve (SPR) as playing a role in pushing up prices (see ‘The Month in Brief’).

The pressure has undoubtedly come from both sides of the demand and supply equation, but most market concern continues to be focused on supply, and especially that from Saudi Arabia. As well as being the world’s largest exporter of crude oil, Saudi Arabia is about the only major oil producer with a significant degree of spare capacity. Whereas world markets were able to survive the loss of Iraq’s exports a year ago, a major reduction in Saudi supplies could not be made up by other producers.

Saudi role

Saudi Arabia was producing about 8.5 mn bpd in early May, of which 7.1 mn bpd were exported. It was the main foreign supplier to the US market during 2003, with 1.7 mn bpd, accounting for nearly 18% of US crude oil imports (see Table A), though volumes have slipped this year to 1.4 mn bpd, or 15% of the total, following a rise in deliveries from Canada and Mexico. It is Western Europe’s second-largest supplier of imports, with 1.3 mn bpd or 15% of the import total in 2003, and the largest single supplier to the OECD Pacific countries of Japan, South Korea, Australia and New Zealand, accounting for 27% of all imports last year, at 1.8 mn bpd.

Most US imports of Saudi crude consist of the country’s medium and heavy grades, reflecting US refiners’ preference for cheaper crude oil blends. Western Europe’s Saudi imports are primarily of light and extra-light grades, which are often required by Europe’s less sophisticated refineries to make increasing quantities of light products such as diesel and gasoline (see ‘Looking Ahead’). More than 75% of Western Europe’s Saudi imports consist of the two lightest grades: for the USA, the proportion of the two light grades is about 36% (see Table B).

Table A
USA: Crude oil imports, 2003

Country	Volume	Market Share
	(th bpd)	(%)
Saudi Arabia	1,724	17.9
Mexico	1,589	16.4
Canada	1,547	16.0
Venezuela	1,193	12.4
Nigeria	838	8.7
Iraq	470	4.9
Angola	361	3.7
Great Britain	347	3.6
Kuwait	205	2.1
Norway	164	1.7
Others	1,208	12.5
Total	9,646	100.0

Source: US Department of Energy, Energy Information Administration
NB: Percentage totals rounded

The four OECD Pacific countries import not two, but three light crude blends from Saudi Arabia. They too need the lightest grades for their relatively unsophisticated refineries, compared with those of the USA. Light, extra-light and super-light crude blends account for 75% of OECD Pacific Saudi imports.

Table B
OECD: Saudi crude imports by grade, 2003

Region	Crude blend
	Light	Medium	Heavy
	(%)	(%)	(%)
North America	36	47	17
Europe	77	9	15
Pacific	75	15	10
Total	61	25	14

Source: International Energy Agency
NB: Percentage totals rounded

OET’s annual survey, ‘World Oil Trade’ shows the USA and Japan as the main lifters of crude oil from Saudi Arabia, with more than 1 mn bpd each. After them, in order, come South Korea, Singapore, China, France and Taiwan. The Saudis are also important suppliers to South Africa, Indonesia, Thailand, Brazil and Turkey.

Kingdom attacks

The attack by terrorists on a compound housing foreign oil workers in the eastern city of al-Khobar on 29 May left 22 dead and world oil markets in turmoil. West Texas Intermediate (WTI) crude rose to a record high of $42.45 a barrel on the New York futures market amid fears of instability inside Saudi Arabia. The assault on the compound, which was linked to al-Qaida, was accompanied by the taking of around 50 foreign oil workers as hostages. It was the second attack in a month to target foreign oil workers. Earlier, another facility at Yanbu on the west coast had been targeted, again resulting in the deaths of foreign workers (see ‘The Month in Brief, May 2004). Yanbu is the principal Saudi Red Sea export terminal, while al-Khobar is close to the main Persian Gulf terminal at Ras Tanura.

There are several terrorist groups operating inside Saudi Arabia, not all of which are necessarily linked with al-Qaida. They have various aims but, in general, two causes are common to most groups: the removal of the ruling house of Saud and its replacement with a more severe form of Islam than that officially practised in the country. Foreign workers are being especially targeted in the belief that they can be frightened into leaving the country, thereby bringing about the collapse of the economy, followed by that of the ruling house itself.

The recent kidnappings and killings have undoubtedly spread alarm amongst the expatriate communities in Saudi Arabia, but their role in maintaining the production and export of oil should not be overstated. The vast majority of the Kingdom’s oil workers consists of Saudi nationals, though certain important maintenance functions are carried out by foreign technicians, many of whom are from the Indian sub-continent. Not all foreigners will leave, in any case, if the experience of other strife-torn oil-producing countries, such as Algeria and Colombia, is any guide.

Perhaps the most worrying development in Saudi Arabia is the growing opposition to the House of Saud from people within the Kingdom, particularly since a significant number of the regime’s opponents are drawn from the middle class. Many of them allege that the regime is corrupt and appoints its members and supporters to key positions in the economy at the expense of better qualified people from the professional classes.

Such opposition puts the Saudi government under pressure to pursue a policy of high oil prices. Mr Naimi has said that $27-28 a barrel would constitute a “fair” price for the OPEC crude basket, which would equate to a price of around $31-32 for WTI. A WTI price of $32-33 would allow Saudi Arabia to balance its budget; but the government would probably want a higher level than this to allow for some further spending designed to appeal to its discontented professional classes. Mr Naimi said in May that consumers could “live with” a WTI price of $35 a barrel.

Raising production

Whatever their social, political and economic problems, the Saudis are likely to be wary of pushing for sustained price levels much above $35, fearing that this would trigger a long term switch away from oil consumption in the main oil-consuming countries, as well as giving a major boost to high cost alternatives to crude oil such as oil shales and heavy crudes (see ‘Looking Ahead’, December 2002), or gas from hydrates (see ‘Looking Ahead’, August 2003) and coal deposits (see ‘Looking Ahead’, June 2003).

Saudi miscalculations on pricing, on the other hand, are partly responsible for the recent high price levels. The Saudis, along with other OPEC members, were heavily influenced by oil analysts’ predictions that oil prices would fall during the second quarter of 2004 as world demand went into its usual seasonal decline. As a result, Saudi Arabia backed proposals at the OPEC meeting in Algiers on 10 February to cut the production ceiling by 1.0 mn bpd to 23.5 mn bpd from 1 April. In the event, OPEC’s April output, excluding that of Iraq, was more than 2.0 mn bpd above the collective ceiling (see Table C). The announcement of a production cut nevertheless helped to turn market psychology more bullish, especially when it became evident that output in April was some 0.4 mn bpd below that of the previous month.

Since then, Saudi Arabia has announced plans to raise its production, and OPEC itself has agreed to higher quota levels. A new concern, however, has begun to emerge. Some commentators have begun to raise questions about the Kingdom’s reserves and production capacity (see ‘Looking Ahead’, April 2004), suggesting that its potential for increases in production is being exaggerated. Despite vehement denials, the Saudis have not been able to shake off all the doubts concerning their future capabilities.

How much oil does Saudi Arabia have?

Saudi Arabia was producing about 8.5 mn bpd in early May. In late May it indicated that output was being raised to 9.1 mn bpd. A year ago, some industry analysts were suggesting that this was near to the Kingdom’s maximum sustainable capacity (see ‘Global Energy Review’ on website). This year, there have been indications that Saudi output capacity is slightly higher than this, though commentators disagree on how much this might be.

The official Saudi position is that production capacity is 10.5 mn bpd, though the oil ministry admits that this level is not sustainable for more than about six months without the drilling of additional wells. The 10.5 mn bpd figure also includes a development of between 0.7 mn bpd and 0.8 mn bpd, which is to be commissioned this year in the Abu Safah and Qatif area.

Beyond 2004, the oil ministry is planning to raise output capacity to 12.0 mn bpd by an unspecified date. After that, it may consider a further rise, to 15.0 mn bpd. Both levels will be ‘sustainable’ levels rather than just for production surges lasting a few months. According to the ministry, the new levels will be capable of being sustained “for 30-50 years”.

It is these longer term targets that are the most contentious as far as Saudi Arabia’s critics are concerned. On the face of it, they should not present too many difficulties given Saudi Arabia’s estimated proven reserves of 262 bn barrels (see ‘Global Energy Review’), giving it 80 years production at existing levels.

Saudi Arabia’s official estimates, however, are generalized rather than being broken down by field and geological horizon. It is thus impossible to verify them independently. These official estimates, moreover, tend to remain unrevised for many years regardless of what level the country has been producing. Within OPEC, reserve figures have enormous political significance when it comes to re-allocating production quota levels for individual countries: hence a tendency for member-states to adopt the most optimistic estimates available. Saudi reserves are certainly large; but exactly how large is impossible to say without much more detailed information on the fields, which the Saudis are most unlikely to provide.

Another way to approach the issue is to look at the production records of the country’s main fields. Here, again, data are scarce, but some important conclusions may be drawn from those that are available. In the first place, the two largest fields, Ghawar and Safaniyah, are more than 50 years old and show several signs of maturity. One controversial assessment presented to the Institute of Petroleum in London in February by US analyst Matthew Simmons was that Ghawar, the country’s largest field, which accounts for nearly 60% of Saudi production, shows every sign of being “almost depleted” (see ‘Looking Ahead’, April 2004). Two other major Saudi fields, Abqaiq and Berri, are also reported to be in decline.

Simmons’ case for Ghawar rests on the increasing use of water injection to maintain pressure in the reservoirs, and cites the fate of Oman’s 250,000 bpd Yibal field, where production fell by 65% between 1997 and 2001, following 30 years of water injection, leaving it producing 90% water and only 10% oil. Similar, if less spectacular declines occurred in some West Siberian fields in the 1990s. Using the Yibal analogy, Simmons states that Ghawar’s production could fall by 30-40% over the next 3-5 years.

The West Siberian example suggests a much less dramatic decline, but a decline nevertheless. The national oil company, Saudi Aramco, appears to concede that parts of Ghawar are in decline, but maintains that the field as a whole is only 48% depleted. Yibal is, in any case, a much smaller field than the 5 mn bpd Ghawar complex and has different geology. The water cut at Ghawar is, in any case, much lower than in many other areas, such as Russia, where in some cases it exceeds 80%. The other large fields, Safaniyah, Berri, Shaybah, Haradh and Zuluf, all have depletion levels of less than 30%, according to Saudi Aramco. Abqaiq, on the other hand, is 73% depleted.

Saudi Arabia may not face an immediate production crisis but there remain some questions about the country’s longer term prospects. In particular, it is far from clear which fields will provide the proposed sustained output levels of 12-15 mn bpd, which Saudi Aramco appears to want to introduce within about three years. One area that is often mentioned in this context is the Rub al-Khali, or ‘Empty Quarter’, in the far south of the country, but major finds there have yet to materialize. Another possibility is to raise recovery factors from existing fields. Saudi Aramco is to use horizontal drilling to increase recovery levels at its 36-year-old 14 bn barrel field at Shaybah. These so-called ‘maximum reservoir contact’ wells are capable of increasing production, but do not always increase recovery rates. Saudi Arabia will probably need some large new fields in addition to horizontal wells if it is to increase its oil production to the levels indicated above.

Meanwhile, Saudi Arabian production will continue to be clearly scrutinized by oil market watchers. Any signs that it is approaching its production capacity are likely to be treated with alarm: the more so since nearly all of OPEC’s spare capacity is now concentrated in Saudi Arabia (see Table C).

Table C
OPEC: Spare production capacity, April 2004

Country	Output	Capacity	Spare Capacity
	(mn bpd)
Saudi Arabia*	8.3	10.5	2.2
Iran	3.9	4.0	0.1
Venezuela	2.5	2.6	0.1
UAE	2.1	2.4	0.3
Kuwait*	2.2	2.4	0.2
Nigeria	2.3	2.5	0.2
Libya	1.5	1.5	0.0
Iraq	2.3	2.3	0.0
Algeria	1.1	1.2	0.1
Indonesia	1.0	1.0	0.0
Qatar	0.8	0.8	0.0
Total	28.0	31.2	3.2

* including half the Neutral Zone
Source: Pearl Oil estimate

THE MONTH IN BRIEF

This section summarizes downstream developments of the previous month. Exploration & Production are covered in ‘Upstream Review’.

High Prices, China’s rising demand and privatization under attack

Oil prices set new records on fears of an interruption to supplies from Saudi Arabia following a terrorist attack on a compound for foreign oil workers in al-Khobar, which killed 22 people (see ‘Focus’). WTI rose to $42.45 a barrel before easing on news that OPEC ministers had agreed to raise their output ceiling by 2.0 mn bpd from 1 July. Markets nevertheless remained tense on continuing fears of instability in the Middle East and shortages of certain products in parts of the USA. Exports from OPEC’s Persian Gulf members started to rise even before the ministers agreed higher quotas in Beirut. Crude oil exports from Gulf countries rose by about 0.5 mn bpd in May versus month-earlier levels, and Iraq’s State Oil Marketing Organization reported May crude exports of 2.0 mn bpd, equalling the highest levels attained since last year’s US-led invasion.

High prices for refined products caused political trouble in various countries. Five people were killed in protests against high fuel prices in Lebanon just prior to the OPEC meeting, while the UK’s Chancellor of the Exchequer, Gordon Brown, was under pressure to cancel a proposed rise in fuel duty due in September as road-users threatened national protests. Gasoline prices started to emerge as an issue in November’s presidential election in the USA, as US markets experienced a succession of record high levels. Energy Secretary Spencer Abraham ruled out any release of government stocks to ease prices, saying that this would reduce energy security, thereby encouraging terrorists to try and disrupt supplies to the USA. Accessity Corporation is to create California’s first vertically-integrated ethanol company to meet the state’s rising oxygenate demand (see ‘Focus’, May 2004).

China has raised domestic prices for diesel in order to damp down the increase in demand and has begun to lift restrictions on refinery building. State-owned PetroChina is to be allowed to double the capacity of its 200,000 bpd Dalian refinery, whilst another government refiner, Sinopec, has received the go-ahead for a 120,000 bpd grassroots facility on Hainan Island. The joint-venture Wepec refinery meanwhile has increased distillation capacity by 25% to 200,000 bpd. China’s net imports of refined products have exceeded 1 mn bpd, as coal shortages force the import of extra fuel oil for power stations. BP has commissioned a 2.3 mn barrel terminal in Canton. India’s new government has halted the privatization of the refining and retail company, Hindustan Petroleum Corporation, saying it will only sell state shareholdings in loss-making companies in future. Papua New Guinea has opened its first refinery: a 33,000 bpd plant at Port Moresby.

Argentina has announced the formation of a new state energy company, Energia Argentina (Enersa) to develop the country’s hydrocarbon resources and electricity infrastructure, following severe shortages of gas and power this year (see ‘Gas and Power’, May 2004). The government blames private companies for recent energy shortages. Argentina sold the previous national oil and gas company, YPF, in the 1990s. Chile has announced plans to import LNG in order to substitute for oil imports and gas deliveries from Argentina, which have been cut as a result of the energy crisis there. Peru, like Argentina, is debating the merits of privatization versus state ownership of the energy industry. Oil industry trades’ unions have called for a halt to further sales of government shareholdings in former state companies. In a separate dispute, Peruvian road tanker operators went on strike in a protest against new legislation requiring them to change the way tankers are filled. Mexico says it has scarcely any scope to increase oil exports owing to rising demand.

GAS AND POWER

New firms move into Australian gas sector

Australia’s booming gas market continues to attract new players. Some companies, however, are not finding success there. Several foreign firms have managed to run up debts and are now putting their assets up for sale. These include US energy merchants, which have lost money in other markets as well (see ‘Gas and Power’, August 2002).

Gas markets in Australia have developed rapidly in recent years, prompted by a series of new finds and the deregulation of gas and electricity markets, which has helped to boost domestic demand. Gas companies, on the other hand, have complained that state government policies do not allow them to charge economic tariffs for transporting gas in many cases. Moreover, some large gas projects have been unable to find sufficient customers to enable them to proceed with their schemes. Gas producers have to contend with the fact that most of Australia’s gas lies in fields off the north and west of the country, while most of their potential customers are located in the south and east of the country.

Mixed fortunes

Australia’s gas and power sectors have provided mixed fortunes for foreign companies. Some now have assets up for sale as they seek to pay off debts run up in Australia and elsewhere. US utility, Edison Mission, for example has put its Loy Yang B power station in Victoria on the block in an attempt to pay off large debts.

Some other companies have managed to sell Australian assets already. These include US utility Duke Energy, which recently sold its entire Australian portfolio to Alinta, a gas producer based in Western Australia. Duke’s assets include gas-fired power stations at Bairnsdale, Newman and Port Headland, and pipeline interests on both sides of the country and in Tasmania. Alinta also acquired Duke’s Glenbrook power station in New Zealand as part of the same deal.

Two other US firms involved in recent asset sales are Dominion and El Paso, which between them held 89% of debt-ridden Epic Energy. Epic has sold its pipeline network in South Australia and neighbouring states and now plans to dispose of its Dampier to Bunbury pipeline in Western Australia. Epic bought the line from the government of Western Australia in 1998 but has since experienced a series of regulatory problems. In 2002, for example, the state’s access regulator ordered a 30% cut in tariffs, threatening the pipeline’s commercial future, until Epic was able to have the ruling overturned by the state’s Supreme Court (see ;Focus’, November 2002). Fears about further adverse regulatory rulings have almost certainly slowed down the sale of the pipeline. There has nevertheless been considerable interest in the sale from Australian companies.

Some non-US assets are also reported to be up for sale, including Hong Kong’s CLP’s stake in the Yallourn power station. While most of the interest in this and other gas and power assets comes from Australian firms, foreign interest in Australia has not entirely dried up. Malaysia’s Genting has been linked with the proposed sale of Yallourn power station, and at least one US utility, TXU, is rumoured to be looking for new assets in the gas and power sectors. Canada’s Enbridge was part of a consortium bidding for Duke assets and other potential investors in various Australian pipeline projects are Singapore Power and Malaysia’s Ranhill.

Australian firms expand

A number of Australian gas and power companies have used the recent round of asset sales as a means of expanding their activities. The former state-owned Western Australian gas producer, Alinta, for example, has used the Duke Energy disposals to give it a major foothold outside its home market in the rapidly expanding markets in the east of the country. Last year, it acquired a series of assets when another US company, Aquila, quit the Australian market.

Another Australian company with plans to expand via a series of acquisitions is Origin Energy, the country’s second-largest retailer of gas and electricity. Origin also has some gas production in Australia and New Zealand and is now seeking to add electricity generation to its portfolio, having bought a power station in Queensland last year.

Among other Australian companies on the acquisition trail are the Australian Gas Light Company (AGL), Australian Pipeline Trust (APT) and GasNet. AGL, already the country’s largest energy retailer has said that it wants to expand its power generation activities. One project already under consideration is the doubling of capacity at its 215 MW gas-fired power station at Hallett in South Australia, where there are local shortages of generating capacity. APT wants to increase its already strong position in gas transmission, though it may encounter opposition from the Australian Competition and Consumer Commission if it tries to expand too aggressively.

Traditional gas companies are now starting to face competition from companies producing natural gas from coal seams. Several projects to produce coal-bed methane (CBM) are under way, including Sydney Gas, which is to develop deposits in New South Wales capable of supplying up to 10% of Sydney’s gas requirements. Most of the city’s gas comes from South Australia, but supplies were interrupted earlier this year by a fire and explosion at the Moomba gas processing plant. Elsewhere in Australia, Queensland Gas is planning to supply CBM to Brisbane. Queensland Gas is one of a number of CBM companies floated over the last few years. Earlier this year, another one, Karoon Gas Australia, announced a new share issue to fund developments in the Latrobe Valley coalfield in Victoria.

To some extent, the newer, smaller companies appear to be leaving some of the older, larger firms behind. Some of the latter have become bogged-down in high profile projects such as the Greater Sunrise field, where development is being delayed by an offshore boundary dispute between Australia and East Timor, and a project to build a pipeline between Papua New Guinea and Queensland, which has encountered difficulties in signing up sufficient customers for the gas.

LOOKING AHEAD

EU fuel oil proposals threaten small refiners

Proposals by the EU to reduce the sulphur content of marine heavy fuel oil are causing alarm amongst smaller refiners, some of whom fear they may not be able to meet the new specifications. Refiners are already having to reduce sulphur levels in diesel and gasoline to comply with new lower limits in both Europe and the USA (see ‘Focus’, May 2004).

Refiners use various forms of hydrogen-treating in order to reduce sulphur levels in distillate fuels such as diesel. The hydrogen comes as a by-product from reformer units, which are used to convert naphtha into gasoline. Refineries normally have sufficient hydrogen with which to run their desulphurization units, which are used primarily to reduce the sulphur content of diesel.

Refineries operating on this basis produce light, low sulphur products such as gasoline and diesel, but they are also left with residues and other intermediate products that are high in sulphur. These are normally disposed of via the fuel oil pool, the fuel oil itself being a blend of heavy residues and lighter liquids. The sulphur limit for fuel oil used in ships’ bunkers is 3.5% in many parts of the world, including much of Europe, providing a valuable outlet for refiners’ excess sulphur.

New limits

The European Commission now wants to reduce this upper limit to 1.5% for all vessels in the North Sea and the Baltic, with a further requirement for fuel used in port areas to have a limit of 0.2%. The new specifications are expected to come into effect in about 2006 or 2007, depending on how long it takes for them to be ratified.

Large refineries already desulphurize their heavy residues, in addition to hydro-treating their middle distillate. Smaller refiners, on the other hand, often lack both the capital to invest in residue desulphurizing units and the hydrogen with which to operate them. A further problem for many European refiners is that their crude slate is becoming higher in sulphur as North Sea oil production declines, forcing them to import a higher proportion of sour crudes from the Middle East and Russia.

Fuel oil markets

Marine bunker fuel consumption in the EU is about 550,000 bpd. Of this, about 200,000 bpd is accounted for by North Sea and Baltic shipping. At present, there are two main fuel oil grades traded in Europe: low sulphur fuel oil (LSFO), which has a sulphur limit of 1.0%, and high sulphur fuel oil (HSFO), where the limit is 3.5%. LSFO normally commands a price premium over HSFO of between $20 and $30 a tonne.

The extra cost of residue desulphurization are expected to widen this price differential to $50 or more per tonne. Some bunkering operations in the Amsterdam-Rotterdam-Antwerp (ARA) region fear that shipowners will limit their purchases there to the minimum level required for voyages in northern Europe and top-up with cheaper 3.5% sulphur material in other ports to cover the parts of their journeys outside the North Sea and Baltic. ARA is Europe’s largest bunkering centre. HSFO would continue to be available in the Mediterranean and from Persian Gulf ports such as Fujairah in the UAE. The Gulf represents growing challenge to traditional bunkering centres such as ARA and Singapore.

The two-tier bunker market may nevertheless not be a permanent feature of the fuel oil business. If the EU were to go ahead with its 1.5% limit, other regions might well follow suit. The International Maritime Organization (IMO) is promoting the idea of a global limit of 1.5% for ships’ bunker fuel.

Lower limits?

The IMO’s proposals would create still further problems for small refiners, some of which are already struggling to meet sulphur limits on automotive diesel. The various proposals on bunker fuels create uncertainties for all refiners since there is as yet no clear timetable for the introduction of the new measures, or even an indication of what sulphur level will finally be adopted. Members of the European Parliament, for example, have indicated that they will propose a much more severe limit of 0.5% when the European Commission’s proposals are debated later this year. The argument is unlikely to be resolved before 2005; the shipping industry will then be given a further year to comply with the new limits.

Refiners of all sizes have complained of the high cost of producing cleaner fuels. Figures from the USA, however, suggest that the capital costs associated with desulphurization, although high, may well have been overstated. The US refining industry initially estimated the capital cost of reducing the sulphur level un diesel from 500 parts per million (ppm) to 15 ppm in 2006 at $9-10bn (see ‘Focus’, October 2003). New studies indicate the cost could be less than $5bn, thanks to improvements in catalysts that allow existing desulphurization units to be run at higher throughput levels.

On the other hand, the logistical costs of new sulphur regulations may well have been underestimated. The US diesel limits will allow a tolerance of only 2 ppm above the 15 ppm limit. While refiners might produce material within this limit, there are fears that product could be put off-specification by contamination from pipelines, barges, road tankers and railcars. Thus ultra-low sulphur diesel might have to be reprocessed before it could be delivered to filling station tanks.

UPSTREAM REVIEW

Western Hemisphere

Discoveries and Agreements

USA: Kerr-McGee has announced that its offshore Ticonderoga discovery could contain reserves of 30-50 mn boe. The field lies under 5,250 feet of water in the Gulf of Mexico and will probably be developed in conjunction with the nearby Constitution field.

USA: Pioneer Natural Resources is to acquire Evergreen Resources for $2.1 bn, to be paid for with 25 mn shares and $850 mn cash. Evergreen is based in the Rocky Mountains and its acquisition will give the combined firm reserves of 6.2 trillion cf natural gas equivalent.

USA: ExxonMobil has sold oil and gas properties in Wyoming and West Texas to US independent XTO for $335 mn. XTO has already bought upstream assets in North and East Texas, Oklahoma, Louisiana and Arkansos this year. The latest deal involves 38 mn bbl of oil and 7,000 bpdoe.

Canada: Murphy Oil is selling its western Canadian oil and gas properties to two Canadian firms, Canadian Natural Resources and Pengrowth for $610 mn. The deal includes producing and undeveloped acreage.

Colombia: Occidental has extended its Cravo Norte agreement with state company Ecopetrol for 10 years to 2018. The deal is aimed at helping to slow down the decline in Colombian output, now 0.5 mn bpd versus 0.8 mn bpd in 1999. Oxy will invest $210 mn in Cravo Norte between now and 2010; Ecopetrol’s share is around $55 mn.

Brazil: State-owned Petrobras is to spend $54 bn over the next six years in an attempt to raise proven reserve levels by one third to 19 bn boe and boost production from 1.5 mn bpd to 2.3 mn bpd, transforming the country into a net exporter of 0.5 mn bpd by 2010 versus net imports of 0.2 mn bpd now.

Pipelines

USA: ConocoPhillips has sold processing gas plants and the 75-mile Raptor pipeline together with associated gas-gathering pipelines to Duke Energy Field Services (DEFS) for $74 mn. The pipeline and processing system handles 110 mn cfd.

Europe

Discoveries and Agreements

UK: British independent Intrepid Energy has sold its 29.9% share of the Buzzard oil field for $840 mn to Petro-Canada. Buzzard’s reserves are put at 1.2 bn barrels, making it the UK’s largest discovery in the last 10 years. It is due on stream in 2006 and could be producing 0.2 mn bpd by 2008, equal to 10% of the UK’s expected production then. Buzzard’s other shareholders are EnCana, operator (43.2%), BG (21.7%) and Edinburgh Oil and Gas (5.2%).

UK: Shell has made a fourth downward revision of its proven reserves of 103 mn boe. The revisions have cut end-2002 reserve estimates by a total of 23% to 14.9 bn boe, angering shareholders and leading to high level resignations (see ‘The Month in Brief’, May 2004).

Netherlands: Work has begun on the 450 bn cf offshore F16-E gas field. Production is expected to begin in 2006 at 150 mn cfd.

Middle East

Discoveries and Agreements

Iraq: Sonoran Energy of the USA has submitted bids to raise production of the Kirkuk field by 0.1 mn bpd and to develop a 60,000 bpd field at Hamrin between Kirkuk and Baghdad. Kirkuk’s output is in decline (see ‘Focus’, January 2004).

Iran: OMV has begun drilling the onshore Mehr block in the Zagros region of southern Iran. The company says it will decide on whether the block is commercial after drilling ends in about mid-August.

Pipelines

Iraq: Iraq is to renew a 30-mile section of the 1.2 mn bpd export pipeline from the Kirkuk field, between Taji and Ceyhan in Turkey. Some 4,000 tons of pipe have been delivered to northern Iraq by Jordanian contractors al-Iman. The line was closed as a result of sabotage in mid-May.

Iran: Iran has raised the capacity of the pipeline connecting Neka on the Caspian to Tehran from 50,000 bpd to 170,000 bpd. The line is used to take crude oil from Russia, Kazakhstan and Turkmenistan to refineries at Tehran and Tabriz. Iran exports an equivalent value on behalf of the three suppliers via the Persian Gulf (see ‘World Energy Review’ on website).

Africa

Discoveries and Agreements

Nigeria: The government has ended bonus payments to oil companies. Firms were rewarded for identifying extra reserves but there have been disputes recently over the size of some payments. Some companies say the scrapping of the bonuses will slow down exploration.

Nigeria: ChevronTexaco is to delay the resumption of output from fields in Delta state following the murder of seven employees there. More than 0.1 mn bpd has been shut-in as a result of communal violence.

Nigeria: China’s Sinopec has signed three-year service contracts for two offshore blocks in the Niger Delta, numbers 64 and 66. State-owned NPDC wants to raise its offshore output from its current 25,000 bpd level and the Chinese government is keen to establish an upstream presence in West Africa.

Nigeria/Sao Tome and Principe: The first acreage award in the joint development zone (JDZ) between Nigeria and Sao Tome and Principe has been awarded. Block 1 was awarded to ChevronTexaco, operator (51%), ExxonMobil (40%) and Equity Energy Resources (9%). Revenues from the JDZ will be split 60:40 in favour of Nigeria. Further awards have been held up by wrangles over upstream terms.

Gabon: US independent Vaalco Energy is to raise the output of its Etame field later this year by up to 8,000 bpd to 23,000 bpd following a new find in May. A further rise of about 10,000 bpd is slated for 2005.

Mauritania: Australia’s Woodside Petroleum has been awarded the operatorship of Mauritania’s first oil field. The 120 mn bbl offshore Chinguetti field is expected on stream in March 2005. Woodside will have a 54% share of the field, followed by Australian independents Hardman Resources (22%) and Roc Oil (4%) together with BG (12%) and Premier Oil (9%) from the UK. Woodside may develop a second oil find at Tiof by 2008 and a gas discovery at Banda.

Morocco: Shell has begun drilling its deepwater acreage in the Agadir-Tarfaya basin off southern Morocco. The area has been described as ‘promising’ and Shell and other companies have been encouraged by new tax breaks for offshore exploration.

Equatorial Guinea: The country’s new national oil company, GEpetrol, has signed a production-sharing contract covering offshore Block O with US Noble Energy (45%) and Swiss Glencore (25%). GEpetrol, with 30%, is down as the operator, but will rely on Noble for technical assistance.

Asia/Pacific

Discoveries and Agreements

China: Norway’s Statoil is to prolong production at the offshore Lufeng field until 2008, reversing a decision to cease output in August. Statoil will use sidetrack drilling to raise production from 6,000 to 10,000 bpd. Statoil owns 75% of the field, CNOOC the remaining 25%.

China/Japan: JNOC has sold three 50% stakes in Chinese oil ventures to other Japanese companies as part of a government scheme to wind up the state company by next year. Its stake in the Japex New Nanhai venture was sold to Japan Petroleum Exploration, while its New Huanan Oil Development shareholding went to AOC and its NMC Pearl River Mouth Oil Development stake to Japan Energy. The sales realised $88 mn.

New Zealand: Genesis Power has agreed to purchase New Zealand Oil and Gas’s (NZOG) production from the offshore Kupe field, which is due to start producing gas in 2007. It will also contribute up to $40 mn of NZOG’s development costs. NZOG has a 15% share of the field.

South Korea/North Korea: South Korea’s state-owned Korea National Oil Corporation (KNOC) is considering participating in the development of a field off Nampo, North Korea. Pyongyang has claimed offshore reserves of up to 40 bn bbl, though this is a wild exaggeration. Energy links between the two halves of the Korean peninsula are tentative and unofficial at present.

CIS/FSU

Discoveries and Agreements

Russia: State-run Rosneft has submitted requests for 19 new exploration licences, 11 of which are close to the 1 bn bbl Vankor field in Eastern Siberia. Rosneft currently produces 0.4 mn bpd of oil and 675 mn cfd of gas.

Russia/Uzbekistan: Lukoil is negotiating with the Uzbek state oil and gas company Uzbekneftegaz for a 70% share of the Kandymsky gas field, the largest field in an area said to contain 8 trillion cf of gas. Uzbekneftegaz will have the remaining 30%. The gas will have to be exported via Russia (see ‘Global Energy Review’).

Pipelines

Kazakhstan: First oil from the Karachaganak field has been shipped via the Caspian Pipeline Consortium’s 140,000 bpd pipeline to Novorossiisk on the Black Sea. The pipeline was opened last year then shut following contamination. Initial flows of 50,000 bpd are expected to rise to 120,000 bpd by December (see ‘Global Energy Review’).