FOCUS

US looks north (and south) as gas starts to run out

Economics teaches that primary production takes place as a series of cycles. On the upward leg of the cycle, production and consumption rise until the most accessible reserves are worked-out, creating shortages and leading to higher prices. The higher prices then stimulate exploration for less accessible reserves and the shortages cease with the production from the new areas. This has been the history of the US gas industry until now; but a new pattern is beginning to emerge that goes against the conventional cyclical pattern of abundance–followed by scarcity–followed by abundance again.

Demand for domestically produced natural gas has begun to outstrip supply, driving up gas prices. Since the end of the 1990s, US prices have more than doubled from just over $2.00 per mn BTU to around $5.60 per mn BTU in 2003, following a decade in which they were generally between $1.50 and $2.50 per mn BTU. The recent rise in prices has stimulated further exploration, pushing onshore drilling to near-record levels of activity. Gas production, on the other hand, is showing no signs of growth (see Table A) and several signs of going into long term decline, despite continuing high levels of exploration.

Table A
US Natural Gas: Production, Consumption and Net Imports, 1999-2003

Year	Production	Consumption	Net Imports
	(billion cubic feet a day)
1999	51.5	62.2	10.7
2000	52.5	64.8	12.3
2001	53.7	61.9	8.2
2002	51.9	64.0	12.1
2003	52.3	60.9	8.6

Source: OET Table 5.2a
BP Statistical Review of World Energy, 2004

This development is particularly worrying for a country that is trying to reduce its dependence on Middle Eastern oil in favour of domestically-produced energy (see ‘Focus’, September 2003). As part of this process, power companies and large industrial users have been switching out of oil into natural gas, initially causing consumption to rise strongly (see Table A). High prices, however, are beginning to produce a switch back to oil (see ‘Gas and Power’) and last year gas consumption in the US recorded a decline of nearly 5%.

The Americans therefore face an uncomfortable choice: either to import gas from the Middle East and elsewhere or to use less natural gas and use more imported Middle Eastern oil instead. As so often when faced with such a dilemma, the US has decided to opt for a third solution: use more gas but import it primarily from producers in the Western Hemisphere, with the favourite supplier, as always, being Canada.

Our (boring) neighbour to the north

The US rarely pays much attention to its northern neighbour. For many years now, the award for the most boring headline in any American newspaper has been won by the line ‘Worthwhile Canadian Initiative’. Canada, however, is suddenly beginning to excite US energy policy-makers, who see it as a vast untapped reserve of natural gas just waiting for the call to start flowing south. Canada’s gas producers on the whole appear happy to oblige their southern neighbour. Some Canadians, though, are not. In any case, it is far from clear that Canada will be able to supply all the gas the US wants. The Americans may yet end up taking more than anticipated from their other neighbours to the south and from just about every other compass direction as well.

Canadian gas production, unlike that of the US, has been growing steadily (see Table B). The growth is hardly spectacular, though, and last year saw a 2% decline and an even bigger fall in exports to the US. The long term outlook is for production in the main fields in the Western Canada Sedimentary Basin, which primarily underlies the province of Alberta, to decline to about a third of its present level by about 2025. It will therefore take some major new finds in order to replace this production from Western Canada.

Table B
Canadian Natural Gas: Production, Consumption and Net Exports, 1999-2003

Year	Production	Consumption	Net Exports
	(billion cubic feet a day)
1999	15.6	8.0		7.6
2000	17.4	8.0		9.4
2001	18.0	8.0		10.0
2002	18.2	8.3		9.9
2003	17.8	8.5		9.3

Source: OET Table 5.2a
BP Statistical Review of World Energy, 2004

Most of these new finds will be of unconventional gas or gas produced in frontier areas. The main sources appear to be as follows:

o Tight gas formations;

o Arctic gas;

o Atlantic gas;

o Coal-bed methane.

Tight gas

Tight gas formations are found in strata with low permeability. As such, they are difficult and expensive to develop since the void spaces containing the gas inhibit the flow of gas through the rock formations. Several such deposits exist, some of which have some impressive reserve estimates attached to them.

One that has attracted considerable recent interest is the Deep Basin in the north-east of British Columbia. Vast deposits of tight gas have been identified here. Estimates of their size range from about 200 trillion cubic feet (tcf) to more than 500 tcf, considerably greater than Canada’s existing proven reserves of conventional gas of just under 60 tcf. The problem with estimates of tight gas reserves is, first, their enormous range and, secondly, the fact that they do not indicate how much of the gas may be commercially extracted.

Perhaps a better indication of reserve levels may be found from just one part of the Deep Basin: Cutbank Ridge, which Canadian independent EnCana is proposing to develop. EnCana’s 500,000 acres are thought to contain some 4 tcf of recoverable reserves, which might well allow production levels of about 400 mn cfd. EnCana and other gas companies stand to benefit from improvements in British Columbia’s upstream terms, combined with a faster approval process for new projects, not to mention advances in drilling techniques, especially horizontal drilling, and the use of wooden mats that allow drilling rigs to operate during the warmer months when the frozen ground becomes boggy.

Arctic gas

The Canadian Arctic also contains large, untapped reserves of gas. Attention is currently focused on the Mackenzie Delta, where some 6 tcf of proven reserves have been identified. The area, however, is remote and expensive to develop. An 800 mile pipeline costing more than $3 bn will be required in order to connect the Mackenzie Delta with the main Canadian gas transmission system in southern Alberta. In addition to passing through difficult terrain, the line faces a host of objections from environmentalist groups.

None of these difficulties, however, have prevented the award of exploration licences in the Delta. There is an active drilling programme in the area and several promising finds have been reported. There is already talk of increasing the capacity of the pipeline from the originally planned 1.2 bn cfd to 1.9 bn cfd and even a proposal for a separate line to carry natural gas liquids from the Mackenzie Delta to Alberta.

Obtaining all the necessary permissions for the gas pipeline will take approximately two years. After that, it is likely to take three years to complete the project, giving a start-up date of 2009.

Even if the line is given the go-ahead in about 2006, the project still faces a further obstacle in the form of competition from a rival and much larger project to pipe gas from Prudhoe Bay in Alaska to the US via the Yukon Territory, British Columbia and Alberta. The Alaskan pipeline is envisaged as having a capacity initially of 4.5 bn cfd, but with a possible subsequent expansion to 6.0 bn cfd. Completion of the smaller line is projected for about 2010.

This line also faces considerable difficulties. Environmentalists object to the further development of the Alaska North Slope. The cost of the line is put in the region of $15 bn with a further $5 bn required to increase pipeline capacity in the US Mid-West to handle the Alaskan gas. The pipeline also faces a political hurdle in the form of possible opposition from the federal government in Ottawa, which may try and slow down the approval process for the Alaskan line long enough to allow the Mackenzie Delta project to be built first.

Atlantic gas

Arctic Canada is not the only part of the country with large, untapped reserves. Canada’s Atlantic coast is estimated to contain huge reserves. The continental shelf off Nova Scotia contains structures said to contain 40 tcf, whilst fields off Newfoundland and Labrador could hold a further 10 tcf. Such figures are, at present, tentative, and exploration in these areas has so far yielded mixed results.

A number of wells have been drilled off Nova Scotia. The most promising area has been the Deep Panuke field, which was explored by EnCana. Nearly 1 tcf were identified in preliminary exploration, but in 2003, the Calgary-based independent announced that this was insufficient for the 400 mn cfd project that it was planning to bring on stream in 2006. The scheme was therefore shelved. A further development, Sable, which is already in production, has had its reserve estimates downgraded, giving rise to fears that the 500 mn cfd field may decline sooner than expected.

A more promising if less well-endowed area is the continental shelf off Newfoundland and Labrador. There are already two oil and gas fields in production, at Hibernia and Terra Nova, though the gas is in both cases reinjected. The most promising gas deposits appear to occur in association with the White Rose oil field, where reserves are estimated between 2 and 3 tcf. Oil production is due to start in late 2005. Gas production, however, will initially be reinjected into the reservoir in order to maximize the recovery of liquids.

Atlantic Canada presents several problems to gas producers. The depth of the water is a major problem off Nova Scotia. Off Newfoundland and Labrador the hazards are mainly connected with bad weather and icebergs. Oil and gas fields either have to be protected by hugely expensive protective barriers or exploited using disconnectable floating production, storage and offloading (FSPO) vessels. Sub-sea equipment also needs to be protected from the undersides of icebergs. All these pose problems connected with storage and safety for natural gas. Production from such fields requires complex technological solutions, which may be up to a decade away.

Coal-bed methane

Another source of Canadian gas said to have enormous potential is coal-bed methane (CBM). Western Canada’s coal deposits are thought to contain some 500 tcf of gas.

A major problem with CBM is the high cost of extracting the gas, which involves drilling large numbers of wells into the coal seams. Around 1,000 wells are required for every 100 mn cfd of gas production. There are also several environmental problems, including contamination of water and damage to the landscape. Plans for CBM production in British Columbia recently aroused considerable public opposition, forcing the postponement of the award of mineral rights to developers.

Where next for the US?

While Canada should be able to provide some of the expected increase in US gas requirements, it is most unlikely to be able to supply more than a small fraction of the amount the US is forecast to need over the next two decades. If the US Department of Energy’s Energy Information Administration is to be believed, the US may require an additional 30 bn cfd of gas by 2025, taking consumption above 90 bn cfd.

At present, Canada supplies around 9.5 bn cfd to the US market (see Table C). Tight gas and gas from frontier areas might provide 2-4 bn cfd of new production by the end of the present decade, but some of this will be needed to offset production declines in Western Canada. Moreover, Canada will almost certainly require increasing quantities of gas for its own use, Even if the EIA’s forecast proves to be too high, it is clear the US needs many other sources of gas supply.

Some may come from the US itself, notably Alaska, and Mexico may be able to supply gas as well. Most gas, however, will have to come from much further afield and be delivered in the form of liquefied natural gas (LNG). The US is already planning for such a contingency. A large number of LNG import terminals are already planned (see ‘Global Energy Review’) and several more have been proposed for nearby countries with the aim of supplying the US market. These include terminals in Mexico and the Bahamas. Canada itself has plans for three regasification terminals.

Table C
Natural Gas: Gross US Imports, 2003

Supplier	Volume
	(bn cfd)
Pipeline
Canada	9.54
LNG
Trinidad & Tobago	1.04
Algeria	0.15
Nigeria	0.14
Qatar	0.04
Oman	0.02
Malaysia	0.01
Total	1.39
Total Imports	10.92

NB: Totals rounded

Source: Cedigaz; BP Statistical Review of World Energy, 2004

Many suppliers

The US is likely to import from several countries by 2010, in addition to those that already supply LNG (see Table C). Its preference is likely to be for suppliers from the Western Hemisphere for reasons of both security and cost. Potential suppliers include Mexico, Venezuela and Bolivia (see ‘Upstream Review’), whilst Trinidad and Tobago could increase the volumes already supplied. The last three countries appear more likely sources than Mexico. Mexico may well serve as a conduit for other countries’ gas if one or more LNG import terminals are built in Baja California, from where gas from Pacific Rim countries might then be piped directly into the western US. These entrepôt terminals, however, are politically controversial in Mexico. Many there object to fact that these terminals are being located in Mexico as a way of circumventing California’s strict planning controls on LNG terminals.

Mexico might supply its own gas to the US, but the government is having difficulties in attracting investment into its gas sector. Proven reserves are falling and output is also in decline (see Table 5.2a). Mexico also has plans of its own to increase the use of gas at home and is already planning to import LNG.

This leaves the US with little choice other than to go outside its own hemisphere for large quantities of LNG. West Africa, Algeria and Norway are among the candidates to supply the US market. Moreover, the US, for all its desire to rid itself of overdependence for hydrocarbons on the Middle East, will also need to look there as well for supplies: in particular to Qatar and Egypt and perhaps even to other countries in that region.

THE MONTH IN BRIEF

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

Market fears, transport tears and exploding refineries

Oil prices set new records in London and New York. WTI broke through the $43 barrier in Late July only to go on and top $44 a barrel in early August, while dated BFO rose above $41 a barrel, as traders panicked over events in Russia, the US and the Middle East. Russian fears centred on the fate of Yukos (see ‘Looking Ahead’), which was facing demands to sell its main producing assets in order to meet government demands for unpaid taxes. Some traders feared that this would halt Yukos’ 1.7 mn bpd production. US worries were mainly concerned with a possible shortage of refined products as refinery throughputs climbed to within 3% of full capacity. Following earlier concerns about gasoline shortages, market attention shifted to jet fuel and heating oil. US jet supplies were sufficiently scarce to push the price of jet fuel above that of gasoline in late July.

Middle Eastern fears were mainly focussed on the lack of spare crude oil capacity worldwide except for Saudi Arabia, Some traders fretted that Saudi Arabia might not have as much spare capacity as it claimed, while others worried about the stability of the government there. Aside from all the speculation, there were some more substantial causes for concern. In Iraq, saboteurs bombed both the northern and southern export pipelines. Oil flows were quickly restored in the south, but exports did not fully recover owing to a shortage of tankers as some vessels were redeployed to other routes whilst the pipeline to Basrah was repaired. In a more worrying development, some vessel-owners began to stop their tankers loading at Basrah, owing to fears of further attacks. Unrest in Iraq is not only causing shortages in international oil markets: Iraq itself is short of products such as gasoline. Road tankers are a frequent target for attack, disrupting both the import and internal distribution of refined products.

Oil distribution is an increasing problem in the US. Mid-July saw imports of crude oil at a record 11.3 mn bpd, but the country’s heavily-used ports and pipeline systems are struggling to move the oil inland. The problem will not have been eased by the announcement by Unocal that it was postponing indefinitely the development of a new deepwater port in the Gulf of Mexico, off Beaumont, Texas. The 1.2 mn bpd terminal, designed to take the pressure off the Gulf’s only other deepwater import terminal, the Louisiana Offshore Oil Port, was due to open in 2007. Unocal appears to have had difficulty in lining up long term users. Russia is suffering from the opposite problem to the US: a shortage of deepwater export terminals (see ‘Upstream Review’). Officials from Rotterdam have proposed the building of large export terminals there which could be fed by the much smaller Russian terminals in the Baltic.

Product markets worldwide have been hit by a series of refinery outages. South Korea chose July to have its first ever strike at an oil refinery, the 650,000 bpd Yeosu unit, belonging to LG-Caltex, and the third-largest refinery in the world. Elsewhere, the problem appears to have been fires and explosions. Fire shut down a 70,000 bpd crude distillation unit at Nippon Oil’s Negishu refinery at Yokohama, Japan, and another fire closed the 150,000 bpd Flushing refinery in the Netherlands, owned by Total and Dow. Norway’s largest refinery, Statoil’s 200,000 bpd Mongstad unit, was also hit by fire, cutting output by half. An explosion, meanwhile, at a desulphurization unit at Germany’s largest refinery, Mineraloelraffinerie Oberrhein’s 300,000 bpd Karlsruhe plant, cut gasoline and gasoil production by a quarter. Nigeria just managed to avoid a strike at all four of its refineries when the government agreed to a programme of repairs. Two refineries nevertheless remain closed following damage to a pipeline. Crude oil exports from Nigeria could also be hit by threatened strikes against foreign oil companies (see ‘Upstream review’). Refiners in Venezuela and Trinidad have offered refining and storage capacity to various Caribbean islands in an attempt to woo them away from traders. The Shanghai Futures Exchange has announced the launch of a yuan-denominated heavy fuel oil contract for 25th August. Austria’s OMV is to take a 51% holding in Romania’s largest oil company, Petrom.

GAS AND POWER

Utilities switch out of gas into fuel oil

A shortage of natural gas is forcing several US utilities to switch to heavy fuel oil. Low fuel oil prices have provided further encouragement. Other parts of the Americas have also seen a rise in oil-burning by electricity generators. In China, a shortage of coal has exacerbated an already tight energy market. High electricity demand there may well delay the planned phase-down of oil-burning for some years.

US demand surge

US utility demand for heavy fuel oil rose sharply at the beginning of summer, as demand for air-conditioning began to increase seasonally. Between mid-May and mid-June, US fuel oil consumption increased by over 20% to 850,000 bpd. High prices made natural gas unattractive to many power companies. At the same time, a surplus of fuel oil in the Atlantic Basin made it an increasingly attractive alternative to gas. Unlike their American counterparts, European utilities have shown very little interest in fuel oil this summer, allowing a surplus to build up in the eastern Atlantic. Mild weather curbed the demand for air-conditioning in several parts of Europe in the early part of the summer and high rainfall over the last year has also helped to ensure the availability of hydro-electric generation. About the only utility seeking fuel oil has been Electricidade de Portugal (EdP), which tendered for three cargoes of heavy fuel oil in July.

The surplus of European fuel oil and its consequent low price was not the only attraction for US power companies. Fuel oil was available more quickly than natural gas. US gas utilities were diverting as much natural gas as possible to premium users such as households rather than supplying large consumers like power stations at lower bulk prices. There was thus no spare gas available in many instances to meet the early summer demand surge for electricity.

In these circumstances, oil becomes particularly attractive. Since it is much easier and cheaper to store than gas, it can normally be obtained from refinery and other inventories. In addition to domestic refinery inventories, US power companies were also able to buy from stocks held by importers in the New York area, on the Gulf Coast and at storage depots in the Bahamas and Caribbean.

As utility demand continued to rise, however, stocks in the US and nearby became depleted. US refiners meanwhile were cracking as much of their heavy residues as possible to meet booming demand for gasoline and middle distillate (see ‘The Month in Brief’), thereby minimizing their production of heavy fuel oil. At the same time, the price of European imports rose as one major oil company accumulated a large long position, causing US demand for fuel oil to abate.

Argentina buys fuel oil

A shortage of natural gas has hit utilities in Argentina as well. Here, low gas prices drove up demand until it exceeded what many producers could supply. Generators were among the first to have their supplies rationed (see ‘Gas and Power’, May 2004). In an attempt to keep the turbines moving, the government signed a deal with Venezuela for 7 mn bbl of heavy fuel oil.

The Venezuelan deal, however, has not gone at all smoothly. Two generators in Buenos Aires complained that the Venezuelan fuel oil was the wrong specification. Other power companies complained that the government was overpaying by as much as 20% for the oil. Many large electricity consumers expressed outrage at electricity price rises of between 30% and 50% following the switch to Venezuelan fuel oil.

Latin America has a fuel oil surplus at present thanks to high production levels from the region’s refineries and the fact that many grades of Latin American heavy fuel oil cannot be sold in the US because they fail to meet utility specifications there.

Fuelling China

China, too, faces a shortage of natural gas, but even more serious from the point of view of the country’s power generators is a shortfall in coal supplies. Coal provides just over 70% of China’s electricity generating mix but power companies are unable to obtain all the coal they require to meet rising electricity demand despite the fact that coal production is rising strongly. Last year, for example, output rose by over 15%.

The problem with coal is transporting it from the coalfields, many of which are in the north of China, to the main areas of electricity demand growth in the south and east of the country. The country’s railway infrastructure is unable to transport all the extra supplies demanded by the generators, forcing them to turn to other fuels. Natural gas supplies are also constrained by the lack of both an internal distribution network and an import infrastructure, leaving oil as the only other option.

Fuel oil demand has soared as a consequence, as have imports. Fuel oil consumption is up by about a third this year compared with 2003. Even so, power generators in many areas are short of fuel. Inland power stations find the cost of transporting fuel oil overland prohibitive in many instances: the more so given the government’s reluctance to allow generators to increase the price of their electricity.

The result has been widespread power cuts and electricity rationing across most of China. The main consequence of this has been a further rise in the demand for oil: this time for diesel fuel. More and more consumers are buying diesel generators to supply their businesses and homes. Diesel demand has grown by a quarter this year and shows little sign of diminishing. China’s long term plans are to substitute natural gas for oil in power generation, but this goal is unlikely to be achieved as long as electricity demand continues to soar ahead.

LOOKING AHEAD

Yukos struggles to pay tax bill

World oil markets have reacted with near-panic to the political and financial troubles of Russia’s largest oil company, Yukos. Fears that the company might cease exporting or even stop production altogether are reckoned by oil traders to have added at least $1 a barrel to world crude prices in the most recent spate of price rises (see ‘The Month in Brief’). The denial of rumours of an imminent production stoppage did little to ease market fears. Meanwhile other private companies active in Russia look-on nervously as the government seeks ways of forcing Yukos to settle tax liabilities amounting to $3.4 bn.

Fighting the oligarchs

Yukos has fallen foul of the Russian authorities in two main ways. In the first place, it owes some $3.4 bn in unpaid taxes for the year 2000. In an attempt to ensure that the arrears were paid, the Ministry of Justice ordered the company’s assets to be frozen and demanded the sale of some of them, if necessary, in payment of the debt. Recently, it relented in part, allowing company bank accounts to be unfrozen. Considerable uncertainty, however, hangs over the firm’s future.

Yukos’ second spat with the government concerns the company’s founder and former president, Mikhail Khodorkovsky, who is in gaol whilst on trial on charges of tax evasion and fraud. Khodorkovsky was reputed to be the richest man in Russia as a result of his large shareholding in Yukos. As such, he was one of a few mega-rich individuals who bought state assets at what were seen as advantageous prices and used them to establish large and successful private companies. These individuals are popularly known as ‘oligarchs’. Khodorkovsky, however, broke the rules of the oligarchy by becoming active in politics in opposition to the government of President Vladimir Putin. Those made rich by Russia’s privatization programme were expected to enjoy their wealth discreetly and stay out of politics.

Large company

Yukos is a large and important company. It is a vertically-integrated oil company – Russia’s largest – with assets in Russia and abroad. It produces some 1.7 mn bpd of oil, of which just under 1.3 mn bpd is exported (see Table D).

The Ministry of Justice has proposed to sell some of Yukos’ prime assets in order to pay off the tax bill. Yukos appears to be resigned to the loss of some of its property but wants to be able to choose which assets are sold. The state authorities have their eye on Yuganskneftegaz, which is Yukos’ largest upstream subsidiary, with a production of 1 mn bpd. Yukos also has another substantial subsidiary, Samaraneftegaz, with an output of 250,000 bpd.

Yukos has proposed various other repayment schemes, including a payment of up to $800 mn from its own cash reserves. It also owns shares in other companies and joint-ventures, notably 35% of Russian oil producer, Sibneft. This shareholding alone is estimated to be worth over $4 bn. A Russian court, however, has seized part of Yukos’ holdings in Sibneft in pursuance of the tax debt, leaving Yukos with only 20% of the company. Mikhail Khodorkovsky has even proposed to pay off the bill by selling his own shares in Yukos.

The problem for Yukos is that paying off the $3.4 bn may not prove to be the end of the matter, since this sum only covers taxes owed for 2000. Further government audits could uncover further unpaid sums. Some asset sales therefore appear inevitable, though Yukos, given the choice, would probably try to dispose of some of its smaller assets first.

Table D
Yukos: Production and Exports, First Half 2004

Oil	(th bpd)
Production	1,710
Crude Oil Exports
Transneft Pipeline	600
Rail to China	130
Other	520
Total	1,250
Refinery Sales
Domestic	400
Exports	335
Total	735
Gas	(mn cfd)
Production	700

Source: Russian press reports

Yukos’ larger assets would undoubtedly appeal to a number of foreign oil companies, but the government has privately indicated that it would prefer to see them go to Russian concerns. Top of the list are two state companies, Rosneft and the gas monopoly Gazprom, though both companies have sought to distance themselves from any asset disposals by Yukos. Two other companies in the frame are Sibneft and Surgutneftegaz. Both might well be interested in Yuganskneftegaz. Sibneft is already part-owner of one of Yuganskneftegaz’s fields, whilst Surgutneftegaz is operating in an adjacent area of Western Siberia to the Yukos subsidiary.

The problem for Yukos is that the government can determine the price at which any assets are sold. The company fears that they may be unloaded cheaply in order to produce a quick sale. What Yukos needs is a process in which as many bidders as possible can participate; but this will take time, and the government’s patience is beginning to wear a little thin.

UPSTREAM REVIEW

Western Hemisphere

Discoveries and Production

USA: Production has begun at three key deepwater fields in the Gulf of Mexico. Anadarko’s Marco Polo came in at more than 15,000 boepd in July, while the Red Hawk field, which is owned equally by Kerr-McGee and Devon Energy was reported running at over 100 mn cfd in August. Marco Polo, which lies under 4,300 feet in Green Canyon Block 608, is scheduled to produce 50,000 boepd in 2005. Red Hawke is in 5,300 feet of water in Garden Banks Block 877. Production capacity is estimated at 300 mn cfd. In the Mississippi Canyon Blocks 613 and 657, Shell has produced first gas from its Coulomb field, the world’s deepest in terms of water depth. Coulomb’s C-3 well lies under 7,570 feet of water. Output is around 100 mn cfd.

Canada: Well completions reached a record high of 10,144 in the first half of 204 thanks largely to a surge in natural gas projects, which accounted for over 70% of Canadian wells up to the end of June. Nearly 80% of all wells were drilled in Alberta, mainly in search of shallow gas (see ‘Focus’). Coal-bed methane also saw a sharp rise in drilling activity, with 227 wells spudded in the first half of the year: up more than 400% on year-earlier levels.

Canada: Husky Energy has obtained permission to develop its 350 mn bbl Tucker oil sands project near Cold Lake, Alberta. Tucker is due on stream in 2006 and peak production is forecast at 35,000 bpd. Suncor meanwhile has reduced its oilsands’ production target by nearly 5% this year to 220,000 bpd owing to maintenance problems and the high price of natural gas used to fuel the production process (see ‘Looking Ahead’, June 2003).

Venezuela: The oil ministry has announced plans to raise the production of extra-heavy crude from 0.5 mn bpd to 1.2 mn bpd over the next ten years. Venezuela has four heavy oil projects at present. Up to 12 blocks could be offered for new projects in the Orinoco Belt, which contains an estimated 270 bn bbl of bitumen. Elsewhere, state-owned Petroleos de Venezuela (PDVSA) announced a large find of light crude in the eastern state of Monagas. The field could contain over 3 bn bbl, according to PDVSA.

Pipelines

Venezuela/Colombia: Venezuela and Colombia have signed an agreement to build a gas pipeline from Colombia’s Punta Ballenas gas fields to Maracaibo in Venezuela. The $170 mn project is due on stream in 2006 and will initially carry 170 mn cfd of gas to petrochemical and other users in Maracaibo. Within ten years, however, the line could be modified to take new Venezuelan gas production to Colombia and parts of Central America.

Bolivia/Peru: Bolivia has begun discussions with Peru over a possible export pipeline to the Peruvian port of Ila, from where the gas would be exported as LNG to Mexico (see ‘Focus’). The move follows a referendum in July where electors voted down a proposal to ban the export of gas. The line faces competition from another scheme to export gas overland to Argentina. Gas companies’ enthusiasm for pipelines may nevertheless be tempered by another result of the referendum: Bolivians also voted to raise taxes and royalties on foreign gas producers from 18-33% to 50%.

Europe

Discoveries and Production

Norway: The Ministry of Petroleum and Energy has approved the development of two fields, Staer and Svale in the Norwegian Sea. The fields are satellites of Statoil’s Norne field, which is due on stream next year at 70,000 bpd. Statoil is to swap some licence holdings in the Norwegian and North Seas with Total which will increase some of the French company’s holdings in the Norwegian Sea whilst raising some of Statoil’s interests elsewhere. In a separate move, the government sold two tranches of shares in Statoil in July, equivalent to about 5% of the company’s stock, leaving the state with 76% of Statoil.

Malta: The Maltese government is reported to be ready to revive offshore oil exploration. Drilling has been restricted by a boundary dispute with Libya, but an improvement in relations between Tripoli and the rest of Europe (see ‘Focus’, April 2004) has encouraged Malta to look again at exploration plans dating back to the 1970s. A government delegation is already in talks with Libyan officials in an attempt to resolve the boundary dispute. The most prospective offshore area is known as the Medina Bank. Seismic studies indicate that it could contain more than 1 bn bbl of oil, though some of this is likely to lie under the zone claimed by Libya. Several major oil companies have shown an interest in the Maltese continental shelf, but none is likely to take on any firm commitments until the boundary dispute is resolved.

Middle East

Discoveries and Production

Iraq: The oil ministry has issued a tender inviting oil companies to bid for contracts to carry out reservoir and engineering studies for the North and South Rumailah and Kirkuk oil fields. All three fields are mature and have not been properly surveyed since the 1980s. It is feared that the Kirkuk reservoir has been damaged as a result of overproduction in the 1990s (see Global Energy Review). The ministry recently declared that it wants to raise Iraq’s production to 3.5 mn bpd as soon as possible and to 6-8 mn bpd by 2010. Output in recent weeks has been below 2 mn bpd.

Iraq: In what is likely to prove a politically controversial move, a Norwegian company, DNO, has signed an agreement with the regional government of Kurdistan covering exploration and development in the Kurdish area of northern Iraq. The political status of the region has yet to be determined and any new Iraqi government may try to curtail or end the autonomy that the Kurdish region has exercised since 1991. The regional government recently said that any income from the new finds in the north should go to the Kurds and not Baghdad. It also wants a share of the revenues from the existing northern oilfield of Kirkuk.

Iran: The National Iranian Oil Company (NIOC) is trying to encourage Indian and Chinese oil companies to develop two oil fields close to the Iraqi border by linking their development to the purchase of Iranian LNG by these two countries. The fields, at Kushk and Hosseinieh, have estimated reserves of more than 1.7 bn bbl.

Yemen: The government has awarded four of the six blocks that were on offer in its latest licensing round. Block 69 in the Shabwah Basin went to Chinese state oil company Sinopec, as did Block 71 in the Masilah Basin. Norway’s DNO , Canada’s TransGlobe and local company Ansan Wikfs took block 72, also in the Masilah Basin, whilst Block 73, to the south, went to British independent, Dove Energy. No bids were received for the remaining two blocks nearby. Yemen is anxious to develop these areas in order to compensate for the decline in its main Masilah field, which averaged 225,000 bpd in 2003, and its 115,000 bpd Marib field. Yemen’s oil production has declined by nearly 15% since the late 1990s (see Table 4.4d).

Africa

Discoveries and Production

Equatorial Guinea: Gas exploration has received a significant boost from the decision by Marathon Oil and the national oil company GEPetrol to go ahead with a $1.4 bn LNG export scheme. Marathon and Noble have announced a discovery in the Alba gas and condensate field, which comes on top of an earlier find described as “encouraging” (see ‘Upstream Review’, July 2004). Interest in oil exploration is reviving with two recent farm-ins by Pioneer Natural resources and Noble in separate offshore blocks, though disappointing drilling results on some blocks have discouraged certain other companies, some of which have offered shares in various blocks for sale.

Gabon: US independent Vaalco plans to increase output from its Etame field following recent discoveries in the area. A new find at Etame 5H is being tied-in to the main field which should boost output by 5,000 bpd to 20,000 bpd from August 2004. Another recent discovery, at Eavom-1, tested at nearly 7,000 bpd.

Namibia: The Kudu gas field is expected to be given the go-ahead by the National Petroleum Corporation of Namibia (NAMCOR) and Energy Africa, which owns 90% of the field and is the operator. The prospects for the offshore field have been greatly improved by an agreement by the national utility NamPower to build an 800 MW generating station at Oranjemund designed to run on gas from Kudu. The project is due on stream in 2009.

Nigeria: Nigerian oil production has been disrupted by a series of strikes by oil workers protesting against pay and conditions. In the latest dispute, Total, the country’s second-largest producer shut-in oil production in a number of fields between 2nd and 7th July. Total produces 0.2 mn bpd in Nigeria. Other foreign companies have been threatened with industrial action, which could disrupt Nigerian oil exports (see ‘The Month in Brief’).

Asia/Pacific

Discoveries and Production

Australia: Queensland Energy Resources (QER) is to close its loss-making Stuart oil shale production facility. The 5,000 bpd plant has suffered from technical problems and cost overruns. QER nevertheless has no plans to abandon shale oil production at the site, and is proposing to build a larger, more efficient plant, using the large resources of shale found near Gladstone, in southern Queensland (see ‘Focus’, November 2002).

India: The government is to extend a block awarded to the UK’s Cairn Energy in Rajasthan following a recent discovery in the Mangala field. Cairn estimates oil-in-place at Mangala to be in the region of 1.1 bn bbl.

Indonesia: Indonesia is offering new upstream terms to foreign oil companies in 10 blocks in frontier areas in the east of the country. Production shares have been improved from the normal split for oil of 85:15 in favour of the government to 65:35, whilst gas terms are to be 60:40, compared with the usual 70:30. OPEC member Indonesia became a net importer of oil this year (see ‘Looking Ahead’, December 2003).

Japan: The Japanese government wants to open part of the East China Sea to exploration in an area thought to contain commercial deposits of natural gas. China has protested that this area lies in a zone disputed by the two countries. Japan has countered that China is exploring in another disputed area.

Pipelines

Malaysia/Thailand: Following a series of delays caused by environmental objections, the Trans-Thai-Malaysia gas pipeline is to open early next year. The line, a 50-50 joint-venture between the countries’ state oil companies, Petronas and PTT, will carry up to 750 mn cfd of gas to various parts of Thailand and Malaysia, and will be developed in stages between 2005 and 2007.

CIS/FSU

Discoveries and Production

Russia: Rosneft and Gazprom propose to develop the 600 mn bbl Prirazlomnoye field in the Pechora Sea off northern Russia. The two state companies plan to commission the field in 2005. Peak production is forecast within five years at 150,000 bpd.

Russia: The Ministry of Natural Resources is putting pressure on companies to reduce delays in bringing new oil and gas fields on stream. Among the developments targeted are the 1 bn bbl Salym field in Western Siberia, which is a 50-50 joint-venture between Shell and Sibir Energy, where work has been held up by arguments over contract terms. Start-up is now planned for 2005. Among other developments under scrutiny by the ministry are Lukoil’s South Khylchuya field in the north of Russia and the Tersko-Kamovsky field in Eastern Siberia, where Yukos holds the licence. Further uncertainty about Russia’s future production levels has been caused by the current dispute between the government and Yukos (see ‘Looking Ahead’).

Pipelines

Ukraine: The government has approved a proposal to reverse the flow direction of the 0.3 mn bpd crude oil pipeline from the Black Sea port of Odessa to the main Russian export pipeline system to Eastern Europe at Brody. This will enable Russian crude to be shipped south to the Black Sea, from where it may be exported. Southbound flows are expected to begin in September.