FOCUS
Libya’s attempts to repair its relations with the UK and USA have begun to bear fruit. Shell has signed heads of agreement covering the development of gas reserves and at least one US oil company has held discussions over a possible return to Libya. Meanwhile, ENI of Italy has announced the start of production from a major new discovery, the Elephant field.
Libya’s oil output is in decline. From a peak of 3.3 mn bpd in 1970, it has fallen below 1.5 mn bpd. The withdrawal of US companies from the upstream sector in 1986, accompanied by both US and UN sanctions, curtailed investment and access to upstream technology. Although some European and Asian companies remained active in Libya, oil developments have remained modest and have, in a number of cases, including the Elephant field, been subject to delays.
Libya wants to increase its output to 3 mn bpd. It hopes to do this within 15 years, and it wants to do it with American help. US companies were instrumental in launching Libya as an oil producer in the 1960s. In 1986, they were ordered out of the country by US President Ronald Reagan following several years of deteriorating political relations between the two countries. Now, the Libyans want them back.
The USA has imposed a trade embargo on Libya since 1981. In 1996, President Bill Clinton signed into law the Iran Libya Sanctions Act (ILSA), which permitted the imposition of sanctions on any foreign company investing more than $20 mn a year in Libya. While no such sanctions were actually imposed, the act may well have discouraged some non-US companies from investing in Libyan oil and gas production. From 1992 to 1999, Libya was also subject to sanctions by the UN.
Since 1988, relations with the USA have been overshadowed by US accusations that Libya organized the blowing-up of a Pan Am airliner over Lockerbie, in Scotland. Libya’s willingness to accept the blame for the Lockerbie bombing and to pay compensation to the victims, together with its renunciation of its programme to acquire weapons of mass destruction, have paved the way for a thawing of relations between Washington and Tripoli. While the USA has not formally ended trade sanctions on Libya, it has lifted a ban on its citizens travelling there and has authorized US companies that were required to leave Libya under the 1986 presidential decree to begin negotiations over their return.
|
Reserves: |
29.5 bn bbl |
|
Reserves production ratio: |
57:1 |
|
Production capacity: |
1.5 mn bpd |
|
Production: |
1.4 mn bpd |
|
Exports: |
1.3 mn bpd |
Source: OET website
Even before the improvement in relations with Washington, the Libyans were taking steps to raise their production capacity. A number of acreage awards were made to European oil companies, including OMV, Repsol-YPF and RWE. OMV and Repsol-YPF were granted exploration rights in the Kufra, Murzuq and Sirte Basins in the north-east of the country, whilst RWE’s acreage was in the Kufra, Sirte and Cyrenaica Basins.
Libya’s aim is to add around 500,000 bpd to its production capacity (see Table A) by 2006, giving a total of 2 mn bpd. The commissioning of the new Elephant field should help to achieve that aim, along with new developments at al-Naga, in Blocks NC-137 and NC-186, and the West Libya Gas Project (WLGP), a combined onshore and offshore project in the north of Libya which is also designed to export gas to Italy (see below). These projects are expected to provide 180,000 bpd of new production in 2004 (see Table B).
|
Area |
Operator |
Forecast production (2004) |
|
Elephant |
ENI |
50,000 |
|
WLGP |
ENI |
45,000 |
|
NC-186 |
Repsol-YPF |
40,000 |
|
NC-137 |
Total |
35,000 |
|
al-Naga |
Petro-Canada |
10,000 |
|
Total |
|
180,000 |
Source:
company data
Output from the new fields will not represent a net gain to Libyan production of the same amount since some other fields are in decline. On the other hand, output from some of the new fields looks set to go on rising after 2004.
The Elephant field, for example, is slated to be producing 150,000 bpd by 2006, whilst output from al-Naga should have risen to 30,000 bpd by 2005. Production from the WLGP meanwhile is set to receive a boost by nearly 50,000 bpd next year from the commissioning of a new condensate stream (see below).
Libya’s largest foreign producer is ENI, which accounts for about 15% of Libya’s total production of 1.4 mn bpd. Up to the early 1980s, however, the most important foreign oil companies were American. During the 1960s, Libya attracted interest from four US majors – Exxon, Mobil, Texaco and Standard Oil of California – as well as from several independents – Conoco, Marathon, Amerada Hess and Armand Hammer’s Occidental. Libyan production rose rapidly from virtually nothing in 1960 to 3.3 mn bpd a decade later.
Relations between the US companies and the Libyan government were uneasy from an early stage. By the late 1960s, Libyan oil receipts were amongst the lowest per barrel in the world. US oil companies were also accused of depleting their reservoirs too rapidly. Following the coup d’état that brought Colonel Muammar Qadhafi to power in 1969, the new regime wasted no time in demanding higher revenues from the 21 foreign companies then operating in the country.
The majors tried to organize a united stand against Libya’s demands but eventually agreed to pay more for their oil. Libya, however, sought greater control over its upstream industry and, in 1972, began to change its participation agreements so as to give the state-owned National Oil Corporation (NOC) a majority holding in all licences. Many companies reluctantly acquiesced in this move, but the four US majors, Exxon, Mobil, Texaco and Standard Oil of California, rejected NOC’s new terms and had 51% of their assets compulsorily nationalized.
Table
C
|
|
Company |
Holdings
Production 1H 1986
Production 1Q 2004
(mn bpd)
(mn bpd)
Occidental
NC102
0.30
0.03
NC103
Sirte
Basin
Akhdar/Sebha
Oasis*
Waha
1.00
0.30
Total
1.30
0.33
|
* Oasis shareholdings were as
follows: |
Following the nationalizations, the government began to convert all existing concession agreements into production sharing agreements. Relations between Washington and Tripoli deteriorated and, in 1981, the USA imposed a trade embargo on Libya. The following year, Exxon and Mobil ceased their operations there. By 1986, there were only five US oil companies left in Libya. In that year, President Ronald Reagan ordered them to leave.
In February this year, however, the White House said that “US companies with pre-sanctions holdings in Libya” were authorised “to negotiate the terms of their re-entry into operations in Libya”. Four companies have reportedly decided to begin talks with officials in Tripoli. They are Occidental, Amerada Hess, ConocoPhillips and Marathon. In the first half of 1986, the fields operated by those companies produced a total of 1.3 mn bpd. Since then their combined output has slumped to 0.3 mn bpd (see Table C).
Since 1986, the holdings of the US companies have been frozen and held by NOC under a ‘standstill’ agreement. The Oasis Oil Company has been renamed Waha Oil Company, whilst Occidental’s holdings have been operated by the Zuetina Oil Company. The four US firms will have to negotiate the terms of their return with the Libyan authorities.
There is unlikely to be a return to the status quo ante. NOC, for example, is unlikely to hand the operatorship of the fields in question back to its US partners as before, following 18 years as operator itself. There is no doubt, though, that the Libyans will welcome a US return, not only for the investment it might bring but, more especially, for the opportunity to acquire the latest US upstream technology, the lack of which has hampered Libyan attempts to raise production capacity in recent years. The Libyans are thus likely to encourage other US companies to explore and produce there, though this will not be possible until Washington formally lifts trade and investment sanctions against Libya.
The return of the Oasis group members might well be accompanied by the application of advanced enhanced oil recovery (EOR) techniques to the Waha field, where output has fallen over the past couple of decades by 700,000 bpd to just 300,000 bpd. EOR could raise output to around 450,000 bpd, according to industry experts.
The ending of US sanctions might also speed up the award of exploration licences in Libya. In 1999 and 2000, NOC announced that it was offering 137 blocks to foreign bidders, but has since made only a small number of licence awards. NOC’s tardiness has been ascribed to a desire to wait until US companies are able to bid for blocks, though some firms with experience of dealing with the Libyan state oil company suggest the reason is that NOC is by nature bureaucratic, cautious and slow.
There have certainly been delays to the Elephant field, which some have blamed on NOC. Foreign oil companies have complained in general about Libya’s upstream terms, including the requirement to curtail production at various times in order to comply with OPEC quota limits. Foreign firms complain privately that NOC is not subject to a similar requirement to restrain production.
Despite this, the large number of blocks potentially on offer, combined with the prospectivity of Libya’s upstream, make Libya an attractive area for oil company investment, Such interest, moreover, is not confined to US firms. European companies in particular are keen to explore in a country that represents a nearby source of low sulphur crude oil. Firms from Italy, France, Germany, Spain and Austria have an important presence in Libya. Recently, though, the country has attracted interest from much further afield, including India and Australia.
|
Country |
Volume |
|
|
(th bpd) |
|
Europe |
|
|
Austria |
13 |
|
France |
33 |
|
Germany |
163 |
|
Greece |
25 |
|
Italy |
420 |
|
Spain |
142 |
|
Switzerland |
45 |
|
Turkey |
81 |
|
Other Europe |
10 |
|
Total Europe |
932 |
|
Other areas |
|
|
Others |
0 |
|
Total |
932 |
Source: World Oil Trade, 2003
One reason for Europe’s interest is that it imports most of the crude oil that Libya exports. Apart from the occasional sale to China and one or two other Asian countries, all of Libya’s crude goes to Europe (see Table D). According to OET’s annual analysis of international oil trade, ‘World Oil Trade’, Libya accounts for more than 25% of Italy’s total imports of crude oil, 12% of the Spanish total and 8% of Germany’s crude imports.
Another area of considerable interest to Europe is Libya’s natural gas. Following the improvement in relations between Libya and the United Kingdom, Shell signed heads of agreement covering a number of gas projects, including a possible export scheme. Libya has substantial proven reserves (see Table E) and already exports gas to Europe.
|
Reserves: |
45.9 trillion cf |
|
Reserves:Production ratio: |
228:1 |
|
Production: |
550 mn cfd |
|
Consumption: |
490 mn cfd* |
|
Exports: |
60 mn cfd† |
* including
gas flared and reinjected
† 2002 figure
Source: OET; Cedigaz; NOC
Gas developments have been somewhat neglected in favour of oil, leaving Libya with potentially large untapped reserves of gas. Most of its gas is produced in association with oil. Output has been falling in recent years, having peaked at 1.5 bn cfd in 1991. Most of the gas comes from the Sirte Basin, from where it is piped to the liquefied natural gas (LNG) terminal and petrochemical plants at Marsa al-Braga.
Libya has ambitious plans to raise production and increase exports. The main new development is the West Libya Gas Project, which ENI is undertaking in partnership with NOC. WLGP covers the Bouri and Wafa fields and is designed to produce 1 bn cfd of gas together with 45,000 bpd of crude oil and a further 50,000 bpd or so of natural gas liquids (NGL).
The project was due on stream in 2000 but has been delayed by US and UN sanctions, which prevented the import of certain items of equipment. ENI now hopes to begin producing oil in 2004, followed by NGL a year later. Eventually, it plans to export some 800 mn cfd of gas by pipeline to Italy.
Libya’s current gas exports go as LNG, with Spain the only purchaser. NOC has a contract to supply Enagas with 150 mn cfd, but recent deliveries have been well below this level (see Table E) owing to technical limitations at the Marsa al-Braga terminal which put the liquid gas off-specification for many LNG receiving terminals. NOC wants to modernize the plant to allow it to supply standard grades of LNG, but work has been held up by the US and UN embargoes on the supply of certain spare parts.
US sanctions have also been blamed for holding up work on ENI’s proposed export pipeline to Italy, though a more important factor has been the lack of firm customers for the gas. A further export pipeline is planned from Libya to Tunisia, but this is dependent on the construction of the line to Italy. Some prospective investors in Libyan gas production see LNG as a better option, especially once NOC has finally refurbished the Marsa al-Braga terminal, which could then have a capacity of 380 mn cfd: far more than is required under present arrangements.
THE MONTH IN BRIEF
This section summarizes downstream developments of the
previous month. Exploration &
Production are covered in ‘Upstream Review’.
OPEC surprised observers for the second time in a row (see ‘The Month in Brief’, March 2004) by announcing production cuts of 1 mn bpd at a time of record demand and near-record prices. Most members said the organization was not responsible for the latter, blaming ‘speculators’ instead. Saudi Arabia’s oil minister claimed mysteriously that up to $8 of recent crude oil prices were “nothing to do with oil”. US Democrats blamed George Bush for the high oil prices because of his policy of buying oil for the US Strategic Petroleum Reserve. After all the fuss, it appeared that OPEC would produce above its 23.5 mn bpd ceiling regardless. US crude prices hit a 13-year high as WTI traded above $38 a barrel; gasoline futures set an all-time record of 118 cents a gallon following an explosion at BP’s Texas City refinery. There was more bad news for BP when a court ruled that it must restrict tanker traffic at its Cherry Point refinery in Washington because of the company’s failure to submit an environmental impact statement when it built an extension to the marine terminal there.
Iraq announced the reopening of its Mediterranean export terminal at Ceyhan in Turkey only to close it once more following sabotage to the pipeline linking Ceyhan to Kirkuk. Insurgents also blew up an oil well near Kirkuk, the first time a well has been hit in Iraq’s second-largest oil producing area. Russia’s Lukoil is to supply refined products to Northern Iraq, despite a ruling by the Bush administration that firms from countries opposed to the Iraqi war would not be considered for such deals. Lukoil circumvented the ban by agreeing to act as a sub-contractor to a US company holding a contract from the Pentagon.
Following his re-election as Russian president, Vladimir Putin has said that the country’s gas monopoly, Gazprom, will be reformed. An experiment to allow independent producers and traders to compete with Gazprom is to be extended. Gazprom may not be too worried for the time-being: it accounts for 90% of Russia’s gas production and all of the country’s gas exports. Following Russia’s problems in the Black Sea (see ‘The Month in Brief’, March 2004), Caspian producers are experiencing difficulties in exporting their oil via the Georgian terminal of Batumi. Georgia’s navy closed the port in an attempt to quell an uprising in the region.
Shell dismayed its shareholders further by announcing a second reduction in its proven reserves and postponing the publication of its annual report, amid stories that its auditors would not sign off the accounts. There was better news for BP, which has conditionally agreed the sale of its one-third stake in the 285,000 bpd Pulau Merlimau refinery in Singapore to the Singapore Petroleum Company. BP has been trying to relinquish its shareholding for several years. BP has also agreed the sale of its retailing and distribution network in Papua New Guinea. The business is to be bought by Canada’s Interoil, which is building a refinery there.
Shell is to pull out of the retail market in Venezuela following the failure of the government to deregulate the market. Crude oil exports from Ecuador were interrupted by a landslide that damaged the main export pipeline. State-owned Petroecuador announced plans to use a privately-owned line instead. Sabotage to a crude pipeline in Nigeria has prevented the reopening of the 125,000 bpd Warri refinery, which was closed a year ago following an earlier attack on the line. The latest attack is a blow to the government’s aim of privatizing the country’s refining industry.
The China National Offshore Oil Corporation (CNOOC) is to build a 400 mn cfd LNG terminal in Zhejiang province. The project also includes a gas-fired power station. China is experiencing power shortages because a rise in coal prices has led to the closure of some coal-fired stations. The government has not allowed electricity prices to rise by the same proportion. Khazakhstan is trying to hasten the development of the giant Karachaganak gas condensate field by opening its development to new investors. Saudi Arabia has invited Chinese, Russian and European companies to explore in the Rub al-Khali (see ‘Looking Ahead’).
GAS AND POWER
A year after the US-led invasion of Iraq, the country’s oil industry shows a few signs of revival (see ‘The Month in Brief’) but the gas and electricity sectors remain in dire condition. The Ministry of Electricity has recently announced plans for the reconstruction of the power industry, but there is a long way to go before Iraq can be assured of adequate and regular supplies. Development of the gas industry meanwhile remains on hold.
Iraq’s electricity sector faces major problems. Power stations, transmission systems and distribution networks were damaged extensively in last year’s invasion, and further damage has been sustained since then as a result of various acts of sabotage. Less than a third of the country’s generating capacity is operating with any degree of regularity and around three-quarters of the electricity grid is reported to be damaged.
The costs of repairing the electricity infrastructure are considerable, and to these must be added the expense of building new capacity to replace the units run down and decommissioned from 1990 to 2003 during UN sanctions. The World Bank estimates that Iraq’s electricity industry requires a minimum of $12 bn between now and 2007.
At the start of the UN sanctions, Iraq had 9.5 GW of generating capacity. The electricity ministry estimates that usable capacity is now around 3.5 GW, though it is able to bring other capacity on line for short periods. The maximum capacity available is estimated as 4.4 GW, compared with a potential demand level of 7.0 GW.
To meet the shortfall, the ministry plans to refurbish some 2.0 GW of generating capacity, and has awarded contracts covering the first 0.5 GW of the total. It is also seeking imports of up to 1.4 GW. Turkey has been asked to provide 1.0 GW, while Kuwait has been approached for 250 MW, with a further 100 MW from Iran and 60 MW from Syria. Talks have also been held with Jordan and Egypt over possible imports. Iraq already has a 1.0 GW interconnexion with the Turkish transmission system. Last November, the two countries signed a protocol to raise this to 5.0 GW. Problems with the Turkish grid, however, restrict the volume of interchanges possible between Turkey and Iraq.
Iraq’s interim government, the Coalition Provisional Authority (CPA), has been allocated $5.6 bn for the electricity sector for the period 2004-7. All the money, however, is to be used for rehabilitation work rather than for new projects. Finance for these is meant to come from private sources, and two models have been proposed by the electricity ministry: build-own-operate (BOO) and build-operate-transfer (BOT). Foreign companies have been invited to propose projects for independent power production (IPP) under these systems.
The ministry has begun talks with the CPA about implementing the policy. It hopes to attract about $7 bn in private investment initially. Before any of this can happen, though, the Iraqis will need to establish a legislative framework for private investment, which may not be easy, given the hostility amongst certain sections of Iraqi society to foreign ownership of energy assets. There will also need to be an electricity pricing regime sufficiently attractive to bring in commercial power companies, not to mention a massive improvement in security both in terms of the protection of power networks from sabotage and the safety of foreign personnel. In this respect, the rise in attacks on foreign civilians in Iraq in recent weeks is particularly worrying.
Some work on rebuilding the electricity infrastructure is already under way. The US military has established a combined-services unit called Combined Joint Task Force 4 to restore initial services and is working on the Daura generating station, the main power plant serving Baghdad. Daura has a nominal capacity of 640 MW, but usable capacity last year was as low as 80 MW. Another plant serving Baghdad, the 1,260 MW Yusifiya station, is being rebuilt by civilian contractors. To the north of Baghdad, Bechtel is rehabilitating the 1,320 MW Baiji generating plant, while in the south of the country, British army engineers have been working on the 800 MW Hartha station and two other smaller generating plants serving Basrah. In various other parts of the country, small gas turbines and diesel generators are being installed.
The north of the country appears to be reasonably well off for generating units and even has a surplus of capacity in some areas thanks to the presence of a number of hydro-electric stations. Before last year’s invasion, power from the north was supplied to Baghdad, but this is not feasible at present owing to the state of the transmission and distribution systems, both of which have been heavily damaged and looted of their cables.
A major problem for the CPA is that much of the rehabilitation programme involves the repair of plant and equipment that were in a poor state of repair even before they were damaged by war and sabotage. What is really required is the construction of several new power stations and the installation of new transmission and distribution lines: tasks which may well be several years away.
Iraq’s natural gas industry is similarly in a bad way. Before the invasion there were ambitious plans to develop gas fields to supply new gas-fired power stations and a further scheme to export gas to Turkey. Iraq’s proven gas reserves are in the region of 100 trillion cubic feet, giving it the 13th-largest reserves in the world, but their development has been neglected in favour of an emphasis on oil production.
The main uses for gas for the foreseeable future look like being for re-injection into oil reservoirs and for the recovery of gas liquids. In these circumstances, gas production is likely to be concentrated in the south of the country. Under Saddam Hussain, the Iraq’s had intended to develop a number of gas fields in the north of the country in order to supply the Turkish market. Turkey, however, has overcommitted to imports of natural gas (see ‘Focus’, October 2002) and is unlikely to want supplies from Iraq for many years. The best medium term market for Iraqi gas is likely to be the domestic power sector. Combined-cycle gas turbine plant could both provide the country with the new generating capacity it needs and allow the closure of less efficient oil-fired stations. Such a development, however, is unlikely in the near future.
LOOKING AHEAD
Shell’s decision to cut its proven oil reserves twice since the start of the year (see ‘The Month in Brief’) has alarmed more than just the company’s shareholders. Some commentators are wondering how many other companies have been overstating their reserve levels and whether the world’s endowment of oil is not a good deal less than current figures appear to show.
About the time Shell was downgrading its reserves, a US banker, Matthew Simmons, was telling an audience during London’s Institute of Petroleum (IP) Week that Saudi Aramco’s ability to raise its oil production might also have been exaggerated. An examination of data on reserves worldwide shows that the oil industry in general is facing a squeeze on reserves. While many companies continue to report net additions to reserves, finding rates have begun to decline. Shell is one of only several large oil companies that have been forced to revise their estimates of future production downwards.
During the latter half of the 1990s, oil company reserves outside OPEC appear to have risen by about 4% annually. Since the start of the present decade, however, reserve additions have been at less than 1% a year. Moreover, most of the recent additions have consisted of upward revisions of previous discoveries rather than coming from new finds.
Many of the new finds have been in deepwater areas, such as offshore West Africa (see ‘Looking Ahead’, February 2004). While these areas contain several promising structures, they are unlikely to contain much more than 100 bn bbl: less than four years’ world oil production at present rates.
Most of the recent new discoveries outside the OPEC countries have been off West Africa or in parts of the former Soviet Union. OPEC itself possesses some 78% of the world’s proven reserves, but even here the picture is not uniformly rosy. A recent survey for OET (see website) shows that several OPEC members are past their long term output peak and that most are struggling to offset the decline of their oldest fields. Until recently, it was generally believed that the larger Middle Eastern producers had a comfortable cushion in terms of both reserves and spare capacity. OET’s survey suggests that this is not the case.
On paper, Saudi Arabia’s tally of proven reserves is impressive: some 263 bn bbl, according to OET’s Annual Statistical Review. Such ‘official’ reserve estimates, however, tend to be exaggerated as part of the negotiation process amongst OPEC members over quota levels, as the OET survey points out. Furthermore, Saudi Arabia’s two main producing fields are more than 50 years old and some of its other large fields are already in decline. All the main fields have production problems of some sort or another.
In his IP presentations, Simmons told his audience that the northern part of the Ghawar field, which has provided nearly 60% of Saudi Arabia’s oil, shows every sign of being “almost depleted”. In the worst case, Ghawar could be on the verge of a steep decline. Two other large fields — Abqaiq and Berri — are already in decline. Perhaps the greatest cause for concern, though, is the lack of any recent large discoveries in Saudi Arabia which might replace the kingdom’s ageing giants. Part of the reason for this may be that Saudi attention has recently been on natural gas rather than oil, though here, as well, reserve levels appear to be lower than once anticipated.
Saudi Arabia, needless to say, disputes this pessimistic assessment of its oil reserves, claiming ‘discoveries’ of 700 bn bbl and the potential to produce some 15 mn bpd for the next half century: about double its OPEC quota level for April 2004. Major new discoveries are predicted for the Rub al-Khali in the south of the country and along the border with Iraq.
Much of the debate about future oil production centres on the interpretation of reserve estimates. In many cases, it is difficult to obtain independent verification of reserve levels, especially where the numbers have important political implications, as is the case with OPEC countries. Oil companies, though. also need to subject their reserve numbers much more thoroughly to independent audit.
In the meantime, it is possible to draw one or two conclusions from the data we already have. In the first place, there have been few, independently verified major new finds since the start of the present decade. According to consultants, IHS Energy, there were no large discoveries at all in 2003.
Previous large discoveries–plus other, smaller finds–could provide about 8–9 mn bpd of new production over the next six years. Over the same period, output from existing fields looks set to decline by about 4 mn bpd, while demand grows by a similar amount, leaving little spare production capacity beyond the end of the decade. Given that it can take up to six years to bring a major new discovery on stream, the oil industry will need to make several major finds over the next year or so if it is to meet the expected demand after 2010.