FOCUS

Russia plays energy security card to boost oil exports

Russia is promoting itself to oil-importing countries as a ‘safe’ alternative to the ‘unstable’ Middle East. This policy has had particular success in the USA, where imports of Russian crude rose from nothing in January to 220,000 bpd in May. US imports of Russian crude for the first nine months of 2002 averaged 71,000 bpd, compared with none in the same period in 2001. Moscow has been rather less successful, however, with its exports of refined products and feedstocks. Several EU countries have called for exports of heavy fuel oil (HFO) from Russia to be more tightly controlled following a tanker accident off the Iberian peninsula.

More oil to the USA

Russia looks set to benefit from rising concerns about energy security. Since early this year it has made a special effort to sell crude oil to the USA. In May, Russian President Vladimir Putin discussed crude deliveries at a meeting with US President George W. Bush, and there have been several other low-level diplomatic contacts between the two countries on how Russia might help reduce US dependence on the Middle East. The Russians have some way to go before they can replace any of the USA’s main Middle Eastern suppliers (see Table A); but there are long-term plans to raise export levels to 1 mn bpd, according to the country’s second-largest oil producer, Yukos.

The Russians expect to be able to supply the extra oil from planned increases in production. They will nevertheless have to improve their existing export infrastructure considerably. Most Russian ports cannot handle tankers large enough to compete with the very large crude carriers (VLCCs) that are used on long haul routes out of the Persian Gulf. The high costs of using smaller tankers have kept Russian crude exports confined largely to Europe, where they can be delivered by pipeline. Yukos, however, has been experimenting with a combination of small tankers and VLCCs as a short-term measure. For the longer-term, the Russians are planning new ports and other infrastructure developments.

This summer, Yukos began moving crude oil in small vessels from the Black Sea to a VLCC moored off Greece, which then took the cargo to the US Gulf. Three separate stems were loaded at Novorossiysk and Feodosiya before being transhipped into the VLCC Astro Lupus, which then sailed to Galveston, Texas, where the crude was lightered onshore in smaller tankers. Three such combined voyages have been arranged so far. The complicated logistics make such voyages expensive and Yukos is looking for ways of cutting costs, for example, by delivering to the Louisiana Offshore Oil Port (LOOP) instead of the Houston–Galveston area. LOOP, unlike the Texan ports, can accommodate VLCCs, cutting out lightering costs in the USA.

Table A
USA: Crude oil imports, January–September 2002

Country	Volume
	(th bpd)
Saudi Arabia	1,480
Mexico	1,454
Canada	1,397
Venezuela	1,201
Nigeria	563
Iraq	483
Other Persian Gulf	242
Russia	71
Others	2,097
Total	8,988

Source: US Energy Information Administration (EIA)

Logistics of exporting

Russia has no deepwater oil ports comparable to those of its Persian Gulf competitors. Its largest terminals can only really handle Suezmax sizes (up to 150,000 dwt), compared to the VLCCs (160,000–320,000 dwt) that most Gulf ports can service. The main terminals are in the Baltic, at Tallinn in Estonia, and Ventspils in Latvia, where the shallow draught restricts vessels to Suezmax sizes, and in the Black Sea. Here the problem is the restricted passage from the Black Sea into the Aegean and Mediterranean through the Bosporus.

A sharp rise in the number of accidents in the narrow waterway which passes through Istanbul has led to the introduction of traffic restrictions by the Turkish authorities. While Suezmax vessels are still able to use Novorossiysk, the ability of the port to handle further Russian oil shipments is limited by the bottlenecks of the Bosporus and the fact that Novorossiysk acts as an export conduit for Kazakh and Azeri oil, as well as exporting Russian crude. In the long term, some means of bypassing the Bosporus via an overland pipeline is likely to be required if the Black Sea exports are to rise sharply, as planned (see ‘Focus’, July 2002). Another problem inhibiting the expansion of Novorossiysk is the fact that the port can be closed at various times of the year by storms. In early December, for example, some four or five 1-mn-bbl cargoes were reported delayed by bad weather.

While the use of Suezmax vessels from Novorossiysk to the US Gulf can be competitive with VLCCs sailing between the Persian Gulf and the US during periods of low freight rates, in recent market conditions Russian exporters have been at an increasing disadvantage. Route rates have risen sharply (see Tables 22 and 23), compared to the early part of the year when Russian exports to the USA started growing rapidly (see Table B)

Table B
USA: Imports of Russian crude, January–September 2002

Month	Volume
	(thousand bpd)
Jan	0
Feb	0
Mar	12
Apr	36
May	220
Jun	78
Jul	79
Aug	100
Sep	104
Ave: Jan–Sept	71

Source: EIA

One further option for Russia’s crude oil exporters is Murmansk, on the Barents Sea. Since the relocation of Russia’s atomic-powered submarine fleet from Murmansk, the port has been available for civilian use. It is only accessible overland by rail, however, making it uneconomic to use as an oil port at present. Russia’s largest company, Lukoil, however, plans to build an export terminal there, linked to the existing oil transport infrastructure by a 950-mile crude pipeline. Lukoil says that Suezmax vessels would be able to use the port, which would be able to handle up to 2 mn bpd. The port would have to be kept open by icebreakers during the winter.

It is unlikely to be built for several years—if at all. The proposal nevertheless shows Russia’s desire to present itself as a large and reliable supplier of oil to world markets. Russian officials have made much of the idea that Murmansk could be dedicated primarily to supplying the US market. In another move aimed at the USA, the Russian government has said it may create a strategic stockpile for use in major world supply emergencies. One Russian company, Tyumen Oil, recently supplied 285,000 bbl of crude oil for use in the US Government’s Strategic Petroleum Reserve.

As if to underline Russian credentials as a reliable supplier still further, Yukos has been criticizing Moscow’s recent support for OPEC in agreeing to restrain its own oil production. Yukos has said further that OPEC’s oil price target of $22–8 a barrel is too high, and that $16–22 would be a more appropriate level (President Bush’s oil-industry friends may disagree).

Two other export schemes have also been proposed recently. One involves the reversal of the Adria pipeline from Hungary to the Adriatic port of Omisalj in Croatia. The line currently allows oil to be imported into Central Europe. By reversing the flow, however, Russia could pump oil through its Druzhba pipeline system from Western Siberia to Hungary, where the Adria could be used to take the crude to Omisalj, from where it could be exported in VLCCs. The second proposal is for a new oil terminal serving the Pacific (including the USA) on the island of Sakhalin. Yukos has plans for a 60,000 bpd terminal there from 2003, but a scheme to raise this to 400,000 bpd is now being proposed.

Upstream links

The main force of Russian policy has been to secure long-term outlets for its rising output of crude oil; but the Russians would also like to attract investment from the USA and elsewhere to their upstream sector. US oil firms are developing fields in Western Siberia and Sakhalin, but have been reluctant to invest in some frontier areas, where they claim tax and other incentives are insufficient. Most of the foreign investment in Russia’s upstream sector has been undertaken by European companies, such as BP, Shell and TotalFinaElf. US companies, on the other hand, have been active in service contracts rather than production agreements.

Table C
Russia: Oil production, January–September 2001 and 2002

Month	Production
	(million bpd)
	2001	2002	Change
Jan	6.86	7.25	0.39
Feb	6.97	7.35	0.38
Mar	6.98	7.39	0.41
Apr	7.03	7.40	0.37
May	7.90	7.49	0.59
Jun	7.21	7.58	0.37
Jul	7.23	7.65	0.42
Aug	7.32	7.79	0.47
Sep	7.30	7.84	0.54

NB: totals rounded and include NGL

Source: OET Table 4.4f

Russia is seeking around $40 bn in upstream investment between now and 2005, some of which will be required to upgrade the export infrastructure. Some of this amount will come from Russian companies; some will be raised via American Depositary Receipts and other external financial instruments, while further sums are provided by direct foreign investment in production and infrastructure schemes. Some foreign companies such as BP, may well take further equity stakes in Russian companies. The end-result, according to Yukos, will be a 20% rise in output between now and 2005 to 9 mn bpd.

Trouble for product exports

Things are going a good deal less smoothly for Russia’s exports of refined products and feedstocks. In particular, the trade in high-sulphur heavy fuel oil is threatened by proposed European restrictions on single-hull tankers following the sinking of the tanker Prestige off the coast of Spain. The 26-year-old single-hull vessel was carrying 76,000 tonnes of Russian HFO from the Baltic to Singapore when it sank in heavy seas causing pollution on the coasts of Spain, Portugal, and France. The EU has since proposed a ban on the transport of HFO in single-hull vessels from 2003 and the phasing-out of single hulls by 2010: five years earlier than originally agreed.

There is now some uncertainty over Russian fuel oil exports. Some EU countries have tried to prevent another 26-year old HFO tanker, the Byzantio, from sailing from the Baltic. Russia has recently made extensive use of older, single-hulled tankers to move HFO to Asia where the combination of low freight rates and high Asian HFO prices have boosted trade. Rates for newer, double-hulled vessels went up by more than 40% on the news that some EU countries wanted to ban older single-hulled ships. Russia’s rather more important export of gasoil should not be greatly affected; nor should trade in other white products.

The refined products’ trade remains important for Russia, accounting for 26% by volume of total oil exports (see Table D). While most products go to Western Europe, the second-largest single market is the USA. Exports to the USA consist mainly of refinery and petrochemical feedstocks and blending components for gasoline. US demand for such products looks likely to rise: perhaps more than that of crude oil. US demand for crude should rise as a result of falling domestic production (see ‘Looking Ahead’, July 2002) but the rise is likely to by curtailed by the fact that almost no new refining capacity is being built in the USA, mainly as a result of environmental restrictions. Russian companies may well adopt the tactics of some of OPEC’s oil producers and buy crude distillation capacity in the USA to provide a guaranteed market for some of their output.

Table D
Russia: Oil exports, 2001

Destination	Volume
	(thousand bpd)
Crude Oil
Germany	582
Poland	353
Italy	295
France	151
Netherlands	136
Hungary	114
Greece	104
Finland	101
Others	1,005
Total Crude	2,841
Refined Products
Netherlands	95
USA	87
France	82
Germany	73
China	58
Italy	53
Others	554
Total Products	1,002

Source: OET World Oil Trade , 2002

Looking eastwards

Over the longer-term, Asia rather than the USA may end up providing Russia’s oil exporters with the greatest growth prospects. China in particular provides a potentially huge market. Moreover, Russia itself has large, untapped hydrocarbon reserves in Eastern Siberia and the Russian Far East which ought, on logistical grounds, to be marketed primarily within East Asia.

The energy security argument ought to work as least as well in Asia as it does in the USA given that more than 70% of Asia’s oil imports come from the Middle East. The Russian share is currently less than 2%. Raising Russian exports to Asia will largely be dependent on the building of new oil pipelines. Yukos, which has the strongest presence in Eastern Siberia, plans a 1,500-mile pipeline from Angarsk to Daqing in China, carrying 400,000 bpd. Russia’s pipeline operator, Transneft, wants to build a much longer line from Eastern Siberia to the Russian port of Nakhodka to allow oil exports to Asia by sea. The Yukos pipeline is the more likely of the two to go ahead, given its lower cost. Sakhalin, ,where Russian and foreign companies are developing a number of new oil and gas fields, could also have 400,000 bpd for export within a few years.

THE MONTH IN BRIEF

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

Oil, weapons of mass destruction, and the US farming lobby

Iraq produced an 11,807-page dossier claiming it had no weapons of mass destruction. Some US and British politicians, doubtless pressed for time, decided against reading it and declared it a sham. Washington has given no official response and continues to prepare for war. Oil markets, on the other hand, are more relaxed about Iraq, preferring to concern themselves with early snow in the USA and Europe, and the interruption of oil exports from Venezuela as the result of a five-day strike.

Following the sinking of the tanker Prestige, some EU countries want to ban the transport of fuel oil in single-hull vessels and phase them out earlier than planned (see ‘Focus’). One country that won’t be receiving fuel oil in any sort of vessel is the Democratic People’s Republic of Korea, where deliveries have been suspended by the USA and its allies following disclosure of a nuclear weapons programme there. DPR Korea received fuel oil in return for a promise not to develop nuclear weapons.

Plans to liberalize the downstream sector in Algeria are threatened by political groups opposing foreign involvement. Israel, meanwhile, is unable to attract any foreign investment in its gas grid, which will now be financed domestically. Kenya and Uganda are seeking private finance to extend the main pipeline between the two countries, which could improve the logistics of supplying refined products to other East African countries. Angola has announced plans for a 200,000-bpd refinery at Lobito. Gabon and the Republic of Congo-Brazzaville will combine some of their declining crude streams in to single blends.

Russia and China refuse to be discouraged by disappointing levels of trade in some new oil futures contracts, and have both announced new ones of their own. Also undaunted is the IntercontinentalExchange, which has started a contract-for-differences in Brent against Brent–Forties–Oseberg (BFO). Trade in its recently established BFO contract is still low.

Spain’s main utilities have been accused of having too much monopoly power over electricity prices. The British government, having introduced a spot market in electricity, is now apparently trying to reverse the effects of this by asking electricity companies to help the troubled nuclear generator, British Energy, by signing long-term power contracts. Creditors of the UK’s largest coal-fired power station at Drax are trying to put a financial rescue package into place. One group of energy producers having better luck is the US ethanol industry. Republican wins in November’s Congressional elections make it more likely that ethanol from corn and other crops will be promoted as a gasoline additive. Ethanol is claimed to be less polluting than methyl tertiary butyl ether and has the additional political advantages of not being imported and of keeping US farmers happy.

GAS AND POWER

British nuclear woes continue

The British government has failed to come up with a long-term plan to restructure the nuclear industry following the financial collapse of the country’s main nuclear generator, British Energy (BE). It has agreed to pay up to $3 bn over the next ten years to enable the company to meet its nuclear waste liabilities, but has so far been unable to decide how to ensure the future of the company as an independent operator.

British Energy’s problems have dragged in several other companies including the nuclear reprocessing firm British Nuclear Fuels Ltd (BNFL), utilities with long-term purchase arrangements with BE, as well as creditors, shareholders, and the British taxpayer, who has so far picked up the bill for the company’s short-term cash problems. BE has been hit by a fall in wholesale electricity prices following the introduction of new electricity trading rules (see ‘Gas and Power’, October 2002). Unlike many other UK generators it does not have any retailing business against which to offset losses made in the wholesale power market. BE also complains that it is unjustly penalized by the government’s climate change levy. The tax is meant to help reduce carbon emissions, but is levied also on nuclear power (while, paradoxically, not being applied to carbon-based fuels used for transport and home heating).

BE wants to renegotiate a costly fuel processing deal with BNFL and is trying to raise more cash by selling foreign assets, including Bruce Power in Canada. Any government bail-out is likely to attract criticism from other British generators hit by falling power prices and may even attract a legal challenge.

Portugal attracts outside interest as power markets liberalize

While some European Union (EU) countries—notably France—continue to resist pressure to deregulate their energy markets, others are pressing ahead with liberalization, including Spain and Portugal, which together form one of Europe’s most rapidly growing gas and power markets. Portugal, in particular, has a new government committed to further liberalization. There are also plans to increase cross-border trade in electricity and gas with Spain, helping to create a single market across the Iberian peninsula.

Deregulating electricity

In 1995, the first steps were taken to liberalize the Portuguese electricity market when a two-tier market was established: one open to competition and the other heavily regulated. The deregulated sector was gradually increased until about 45% of the total electricity market was deregulated. This proportion nevertheless remains well below the EU average, which is around 66%, and the new government declared in April, shortly after its election victory, that it wanted to speed-up deregulation.

There is certainly plenty of scope for further deregulation, but the government will have to take some radical and politically controversial measures if power markets are to be opened-up completely. One of the main issues is the role of the partly state-owned utility Electricidade de Portugal (EDP).

EDP controls 85% of the country’s generation, over 95% of electricity distribution and 30% of the transmission network via its shareholding in the national grid company, Ren. The remaining 70% of Ren is in government hands. EDP owns 7.2 GW of generating capacity, of which nearly 55% is hydroelectric. It also has a 10% shareholding in the country’s two main independent power producers (IPPs), Pego and Tapada do Outeiro. As a result, EDP dominates both the regulated and deregulated sectors of the market. The government wants to see more IPPs and the establishment of independent distribution networks, but EDP’s market dominance looks set to continue for many years.

The government is unlikely to do very much to undermine EDP’s position since it is anxious to retain a large vertically-integrated utility, partly to protect the Portuguese electricity industry from falling under the control of larger foreign companies, and partly to develop EDP as a major player in the combined markets of Portugal and Spain. To help achieve the latter, EDP concluded a strategic alliance in 1998 with Spanish utility Iberdrola, under which EDP acquired a 3% shareholding in the Spanish company, while Iberdrola took a cross-holding of 4% in EDP.

The alliance soon hit trouble, however, when EDP joined a Spanish bank Caja de Ahorras de Asturia (Cajastur), in bidding for another Spanish utility, Hidrocántabrico. The alliance was ended in 2000. The following year, though, Iberdrola sought to revive the arrangement. Lisbon remains wary of any tie-up, fearing that Iberdrola could eventually dominate the alliance. For its part, Iberdrola wants to grow quickly in order to avoid being taken-over by a larger utility. Among its other plans are the development of a gas supply business in Spain following the completion of market deregulation there in 2003.

A larger foreign presence in the Portuguese electricity industry nevertheless appears to be about the only way to open the market to full competition. A further help to liberalization would be the integration of Portugal’s electricity grid with that of Spain through the building of further interconnectors. One of the benefits of the latter might be the development of a spot market in electricity in Portugal based on the existing Spanish pool market.

More gas

The deregulation of Portugal’s electricity market is also likely to lead to large benefits for gas producers in the power generation business. Lisbon wants more IPPs to meet a shortfall in generating capacity. Ren has failed to build up enough new capacity to keep pace with demand growth of more than twice the EU average, forcing Portugal to import from Spain. The capacity shortage is exacerbated by the high proportion of hydro-electricity in the mix, since availability of such units varies considerably according to rainfall levels. Hydroelectric power, moreover, is concentrated in the north of the country, while demand is mainly in the south.

The net result of this is likely to be the building of more stations in southern Portugal, and many of these will be gas-fired. EDP has already announced three new gas plants totalling 560 MW to be built between now and 2007. In addition to this, several existing plants will be converted from oil and coal to run on natural gas.

Some of the gas will come in via Spain, which is increasing the number of its LNG import terminals. Portugal, meanwhile, is planning its own regasification terminal to receive LNG from Nigeria. The development of pipeline links between Portugal and Spain could assist the growth of an Iberian gas market. The main issue now is whether the two countries can put in place the necessary regulatory framework to make a common Iberian market operate effectively.

LOOKING AHEAD

Canadian tar sands developments threatened

High oil prices have encouraged the development of tar sands in Canada, enabling it to raise its output of petroleum liquids, despite the decline of many old conventional oil fields. Further developments are now threatened, however, by higher than expected extraction and processing costs and by the prospect of environmental restrictions on new developments.

Growing output

Canada produces some 2.3 mn bpd of crude and NGL, of which 0.7 mn mbd comes from tar sands, where bitumen is recovered and processed into a synthetic light crude oil (syncrude). The growth of syncrude production has helped to prevent a decline in Canadian liquids production as the older, conventional oil fields go into a natural decline of about 4% a year. Current plans envisage a sharp rise in syncrude production, with output levels forecast at more than 3 mn bpd in 2015.

This figure should be easily achievable in terms of the country’s reserve base of bitumen. Oil-in-place is estimated by the International Energy Agency at 1.6 tn bbl, with 310 bn bbl regarded as recoverable. This latter figure dwarfs the figure of only 9 bn bbl estimated by OET (Annual Statistical Review 2002, Table 1.1) for Canada’s reserves of conventional crude oil.

Another factor assisting in the growth of syncrude production has been the high price for crude oil in the world market since late 1999. At the same time, improvements in technology have helped lower operating costs of syncrude plants to $12 a barrel or less to produce light, sweet synthetic crudes. Some 60 schemes have been announced to recover oil from tar sands. Some of these involve the mining of oil shale and then processing into syncrude, while others inject steam into underground seams, forcing the bitumen to the surface as a viscous liquid before upgrading it into a much lighter syncrude. All these operation require large inputs of energy to heat and upgrade the bitumen and copious amounts of water to make process-steam. Some operations require significant amounts of labour. It is in all these areas that problems are beginning to emerge.

Putting a brake on expansion

High oil prices, while generally encouraging the development of tar sands, also mean high operating costs in terms of the oil and gas required to heat and process the bitumen. Fuel costs account for about 40% of operating costs where steam injection is employed. Labour costs have risen sharply in northern Alberta, which is well away from the province’s main population centres. Equipment costs have also been rising; but perhaps the main problem at present is a potential shortage of water.

Water is used in a variety of applications, both to extract bitumen from surrounding rock and as process-steam. The recent growth of tar sands activity has led to a rapid rise in groundwater extraction. Around a quarter of Alberta’s groundwater is estimated to be used in bitumen extraction. So alarmed have the local politicians become by this that the provincial government is considering ending the practice of allowing oil companies free access to groundwater. Various measures are being examined, including charging for water and mandatory recycling.

Syncrude production typically requires the extraction of more than four barrels of water for every one barrel of synthetic crude. The water issue is now being used to oppose several new tar sands projects. Among those protesting are environmentalists demanding protection for wetlands used by migratory birds, and farmers complaining that their own boreholes are running dry. Koch industries has been ordered by the Alberta Energy and Utilities Board to come up with a revised water management plan for its $2.3bn Fort Hills tar sands scheme, which aims to produce just under 200,000 bpd by 2008. Another project under fire is Canadian Natural Resources’ Horizon development, which involves the diversion of a river in northern Alberta.

It is now looking increasingly likely that some projects will be delayed, or even, in some cases, cancelled. Cost overruns of over 50% are being reported by some projects and several companies and consortia have recently revised their budget estimates for future projects upwards by 30% or more.

As if the local environmental issues were not enough to cope with, tar sands developments now face a further threat from the federal government. Ottawa is considering whether or not to ratify the Kyoto protocol on climate change. A ‘yes’ vote could see the imposition of extra taxes on heavy oil and bitumen projects, which oil companies estimate would add up to $1 a barrel to their costs. Some firms like Koch are already delaying projects until they know which way the country’s politicians will jump.