FOCUS

Japan seeks greater energy security

Dependent on the Middle East for over 80% of its oil supplies, Japan is trying to diversify its energy slate away from oil. Gas and nuclear power are the favourites to replace some of the country’s oil consumption. Oil is nevertheless unlikely to be replaced quickly and will remain the dominant source of primary energy for the next 25 years.

Oil dependence

Oil accounts for just over 49% of Japan’s primary energy consumption (see Table A). Of the country’s 5.5 mn bpd consumption, all bar 30,000 bpd has to be imported (see Table 4.4f). The imports themselves come overwhelmingly from the Middle East. In 2003, some 86% of Japan’s crude oil imports came from that region (see Table B), as did 19% of its imports of refined products. Of Japan’s total oil imports last year (crude plus products), just over 82% were accounted for by the countries of the Middle East.

Table A
Japan: Primary energy balance, 2003

Source	Consumption
	(mn toe)	(%)
Oil	248.7	49.3
Coal	112.2	22.2
Natural Gas	68.9	13.6
Nuclear Power	52.2	10.3
Hydro-electricity	22.8	4.5
Total	504.8	100.0

NB: Totals rounded.

Source: BP Statistical Review of World Energy, 2004.

Japan’s energy balance is dominated by oil. Apart from its use as a transport fuel, it is also used in power generation and as a feedstock for petrochemical production, particularly in the form of naphtha and condensate. The continuing use of oil for electricity generation, long after oil has ceased to be used for this purpose in most parts of the industrialized world, is a result of high demand for electricity during the high growth years of the 1980s and early 1990s. New power stations could not be built quickly enough to keep up with demand: a situation that was made worse by a shortage of flat land for new, large generating plants.

The petrochemical industry, denied a nearby source of ethane for olefin production, turned instead to liquefied petroleum gas (LPG), naphtha and condensate. These feedstocks also enabled the production of propylene, polypropylene and other plastics and fibres required by Japanese industry during the ‘miracle’ years.

Searching for oil

This high dependence on oil, coupled with Japan’s lack of any large reserves of its own has worried successive governments for more than 30 years. Efforts to alleviate the problem, however, have met with only limited success. An important aim of past governments’ policies was to secure oil production overseas to offset the country’s excessive reliance on a few Middle eastern suppliers (see Table B). To this end, a government body known as the Japan National Oil Corporation (JNOC) was established in 1967 to encourage and help finance oil production abroad by Japanese companies.

Table B
Japan: Crude oil imports, 2003

Country	Volume	Market Share
	(th bpd)	(%)
Middle East
Saudi Arabia	1,179	30.1
UAE	815	20.8
Qatar	442	11.3
Kuwait	380	9.7
Iran	310	7.9
Oman	240	6.1
Others	24	0.6
Total	3,390	86.4
Asia/Pacific
Indonesia	162	4.1
Australia	62	1.6
China	52	1.3
Malaysia	29	0.7
Vietnam	24	0.6
Brunei	17	0.4
Others	1	*
Total	347	8.8
CIS
Russia	9	0.2
Total	9	0.2
Western Hemisphere
Mexico	10	0.3
Ecuador	4	0.1
Total	14	0.4
Africa
Nigeria	71	1.8
Angola	48	1.2
Others	53	1.4
Total	172	4.4
OECD Europe
Norway	4	0.1
Total	4	0.1
Unclassified	13	0.5
Total World	3,936	100.0

NB: Totals Rounded.

* Less than 0.1%.

Source: World Oil Trade; Blackwell Publishing, 2004.

By 1990, projects assisted by JNOC supplied 470,000 bpd of oil to Japan, equivalent to 13% of the country’s total imports of crude oil at that time. Around two-thirds of that oil, however, came from the Middle East, principally from concessions in the Neutral Zone of Saudi Arabia and Kuwait operated by a private Japanese company known as the Arabian Oil Company (AOC). AOC’s concessions, however, had expired by 2003, leaving a great hole in Japan’s overseas production. The role of JNOC also came into question about this time as Japan found itself without the levels of overseas production for which previous governments had hoped, but having spent enormous sums in trying to acquire them.

The government is now engaged on selling off the holdings JNOC built up in companies that were financially supported by it. The most recent sale was for Inpex Corporation, which has producing assets in Indonesia, UAE and Iran, giving it an output of about 300,000 bpdoe, and shares in major undeveloped fields, such as Kashagan in Kazakhstan and Iran’s Azadegan field. In future, Japan will have to rely on companies such as the large, diverse conglomerates known as sogo shosha, such as Mitsui, Marubeni and Mistubishi, for the expansion of its overseas production. The main interest of the sogo shosha, however, tends to be more in natural gas than oil. Gas, though, is also where the government’s attention is moving.

Switching to gas

The gas will still have to be imported but gas has the great advantage of not being concentrated in the Middle East. Japan imports liquefied natural gas (LNG) from nine countries. Only 23% comes from the Middle East, compared with 86% dependency in the case of oil (see Table C). The main supplier is Indonesia, and Asia/Pacific countries account for 75% of Japanese gas imports.

The government wants to bring in more gas from Asia: in particular, from Russia. The main area of interest is the Russian island of Sakhalin, just to the north of Japan, where a major offshore oil and gas project is under way. Japanese power companies have already agreed to import LNG from there, and there are longer term plans to build a gas pipeline connecting Sakhalin with Japan. In addition to any undersea import line, Japan will require an onshore system of transmission if the use of gas is to become more widespread. Japan’s mountainous topography and its susceptibility to earthquakes, however, make the construction of gas pipelines something of an engineering challenge.

Some of the imported gas will undoubtedly replace gas manufactured by local gas companies from oil-based feedstocks. The government hopes that household and commercial customers will switch to natural gas as well. There are even plans to convert one million motor vehicles to run on natural gas by 2010. There are also several proposals to build new, gas-fired power stations as the gas and electricity markets become deregulated.

Table C
Japan: LNG imports, 2003

Country	Volume	Market Share
	(th bpd)	(%)
Asia/Pacific
Indonesia	2.3	30.1
Malaysia	1.6	21.0
Australia	1.0	12.9
Brunei	0.9	11.2
Total	5.8	75.2
Middle East
Qatar	0.9	11.3
UAE	0.7	8.6
Oman	0.2	2.7
Total	1.7	22.7
Western Hemisphere
United States	0.2	2.1
Trinidad & Tobago	*	0.1
Total	0.2	2.2
Total	7.7	100.0

NB: Totals rounded. Figures refer to contract volumes only.

* Less than 100 mn cfd.

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

Sakhalin is not the only potential source of Russian gas. Gas could be supplied from fields in mainland Eastern Siberia. Japan even has hopes of finding gas of its own. The East China Sea is thought to contain commercial reserves of natural gas; but China and Japan have yet to agree offshore boundaries and China was recently reported to be conducting exploration activities in areas of the continental shelf that are claimed by Japan.

More nuclear?

A demand scenario recently issued by Japan’s Ministry of Economy, Trade and Industry (METI), shows a rise in the market share of natural gas in its base case scenario from 13% to 18% by 2030 (see Table D). This looks quite feasible on existing plans for overseas production and Japanese infrastructure developments. METI’s base case also shows an increase in the share of nuclear power in the country’s energy balance from 13% to 15% over the same period. This looks rather less certain.

Opposition to nuclear energy is high in certain sectors of society. Moreover, the nuclear industry’s popularity has not exactly been enhanced following a series of accidents in nuclear plants, even though many of these had nothing to do with radioactive materials (see ‘The Month in Brief’, September 2004). More importantly, perhaps, many of Japan’s power companies are revising their forecasts of future electricity demand downwards in the light of predictions of a fall in the country’s population in the next decade.

The high capital cost of nuclear power stations may also stay the hand of some electricity companies when it comes to building new generating capacity, particularly with the arrival of competition arising from deregulation of the electricity industry. New market entrants are indicating that any power stations they might build are likely to be gas-fired. Japan’s existing generators are also adding to their gas-fired capacity with new LNG stations. Gas is likely to receive a further boost if nuclear power does not increase as planned, since it is the only realistic alternative method of generation that allows Japan to meet its commitments under the Kyoto Protocol.

More gas generation might even permit Japan to burn more coal. Coal consumption in METI’s base case remains more or less static around 670 mn boe a year between now and 2030 apart from a small increase over the short term (see Table D). Coal could, however, substitute for some nuclear and oil capacity, though consumption is unlikely to rise by very much. Oil’s role in power generation looks set to fall from its 18% share in 2003 to less than half that proportion over the next 10-15 years.

Role of oil

Oil’s role in the energy balance as a whole, on the other hand, is not likely to fall nearly so sharply. METI’s base case sees a 15% decline in consumption in volume terms between 2000 and 2030 and a greater decline in its share of energy demand. Oil nevertheless remains the most important fuel by far, even in 2030, with 38% of the energy market. Gas, the second-largest source comes a long way behind with 18% (see Table D).

For this reason, Japan will need to continue its search for sources of oil outside the Middle East. As with natural gas, Russia represents an important alternative source of supply. The main source of Russian crude would, in the first instance, be Eastern Siberia; but the import of oil from this source would require the construction of an export pipeline.

Japan, however, faces competition from China for Eastern Siberian oil. The Chinese have been discussing a pipeline of their own from Eastern Siberia, linking-up with their own pipeline system at Daqing in north-eastern China. The line, which is also being promoted by the Russian oil company, Yukos, would have a capacity of 600,000 bpd.

The Japanese are promoting a rival scheme for a larger pipeline to the Russian port of Nakhodka, on the Sea of Japan. The line, which also has the support of the state-owned Russian pipeline company, Transneft, would have a capacity of 800,000 bpd. At $10.8 bn, the Transneft project would be considerably more expensive than the shorter pipeline to Daqing. On the other hand, the Nakhodka route would allow Russian oil to be sold to a range of buyers in East Asia, unlike a line dedicated solely to supplying the Chinese market. There is unlikely to be sufficient oil in Eastern Siberia to warrant the building of more than one pipeline for the time-being. The Yukos line may yet fall victim to the problems that have overwhelmed Russia’s largest oil company (see ‘Looking Ahead’, August 2004). Meanwhile, Japan is reported to be offering soft loans to encourage the building of the Nakhodka line.

Energy security

Energy security is not a concern that is confined to Japan. Much of East Asia is dependent on the Middle East for a large proportion of its imports of crude oil. METI has therefore proposed a system of regional co-operation designed to prevent oil shortages across the region and the high prices that accompany them.

Table D Japan: METI base case demand outlook to 2030 Source	FY2000		FY2010		FY2030
	(mn boe)	(%)	(mn boe)	(%)	(mn boe)	(%)
Oil	1,723	47	1,623	43	1,466	38
Coal	673	18	698	18	667	17
Natural Gas	497	13	572	15	679	18
Nuclear Power	472	13	535	14	566	15
Hydro-electricity	126	3	132	3	126	3
LPG	120	3	120	3	145	4
Other	94	2	107	3	170	4
Total	3,705	100	3,787	100	3,818	100

NB: Totals rounded. Fiscal year runs from 1st April.

Source: METI.

Amongst METI’s ideas are a proposal that countries in the region should build up stockpiles and co-operate over their use during short term emergencies. In addition, METI wants to see the freer movement of oil and LNG and an end to restrictive practices by suppliers, especially the charging of higher prices for oil and gas in Asia. It also wants its neighbours to get together in order to promote better oil transport links between producers and the region.

THE MONTH IN BRIEF

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

Record freight rates and LPG prices plus privatization (at last) for GdF

Oil prices fell sharply, pushing Brent below $40 a barrel before rising again on fears of a heating oil shortage in the US. Low inventories there kept crude prices stronger in the US than in Europe or Asia. Crude prices in Asia were hit by the unloading of extra volumes of heavy, sweet Indonesian crudes following an accident affecting the 125,000 bpd Balongan refinery. Indonesia’s Minas crude fell by more than $15 a barrel compared with its previous peak in October. The glut of heavy, sweet crudes in Asia and high freight rates combined to bring down the prices of competing sweet crudes from West Africa. The freight rates themselves were a consequence of record tanker fixings. Liftings worldwide exceeded 37 mn bpd for the first time ever in November. Mid-November freight rates between the Persian Gulf and Asia touched Worldscale 350: more than three times their level two months earlier. The official price of the benchmark Saudi Arabian LPG reached a record $463 and $473 a tonne in November for propane and butane, respectively.

High oil prices have reduced demands within OPEC for a switch from pricing in US Dollars to some other currency or basket of currencies (see ‘Looking Ahead’, May 2004). An internal review conducted by the cartel concluded there was no need for any change. Venezuela and Russia have agreed to mediate between OPEC and non-OPEC producers in an attempt to ‘stabilize’ oil prices. Iraq’s State Oil Marketing Organization (SOMO) has introduced measures to compensate buyers for variations in crude quality and interruptions to supplies caused by sabotage to Iraqi oil installations. An attack on the export pipeline to Ceyhan in Turkey interrupted flows for 13 days before deliveries were resumed. In a further incident in late November, one of the two main crude export pipelines to the Basrah Oil Terminal was damaged. The oil ministry itself was attacked, as were pipelines serving the Bai Hassan oil field and the country’s main refinery at Baiji. A number of mainly Sunni politicians called for Iraq’s elections, scheduled for 30th January, to be postponed for up to six months because of the deteriorating security situation there. The interim government said it was “determined…to hold (the) elections on time.”

A general strike was averted in Nigeria after the government agreed to cut the price of some fuels. Trades Unions had earlier threatened to disrupt oil production and exports unless a recent rise in retail prices was rescinded (see ‘Looking Ahead’, November 2004). The government of Indonesia has been bolder than that in Nigeria and announced that it will cut fuel subsidies next year. Prices are expected to go up sharply as a result. Buyers of Nigerian crude objected when the state oil company set its light, sweet crude prices above those of Brent for December despite high freight rates (see above) that had depressed the spot prices for Nigerian grades.

International oil companies are wary of building new refinery capacity, fearing a collapse in the present high refining margins. National oil companies appear more sanguine. Saudi Aramco is to spend $800 mn to upgrade its refineries to meet new sulphur standards in Europe and Asia, whilst China’s Sinochem has been given official clearance by Peking to take over the 275,000 bpd Inchon refinery in South Korea. Another Chinese state company, however, China Aviation Oil, has been told to withdraw its bid for a 21% stake in the Singapore Petroleum Company’s 274,000 bpd Pulau Merlimau refinery. The Abu Dhabi Oil Refining Company has announced plans to produce green diesel. Egypt is to privatize a number of oil, gas and petrochemical companies, including Alexandria Lube Oils and Egypt Gas. It will also sell 40% of the Alexandria Petroleum Company, which owns the 100,000 bpd Alexandria refinery. After much delay (see ‘Looking Ahead’, July 2004) the French government has approved the privatization of the two giant state utilities, Gaz de France and Électricité de France.

GAS AND POWER

Australia debates regulation as gas production increases

Following his election victory this summer, Australia’s Prime Minister, John Howard, has unveiled a number of new policies on gas, designed to improve the efficiency of the energy markets inside Australia. Many in the energy industry are not convinced that the government is on the right tack, and have criticized both the measures and, more generally, the way the government conducts policy. Several gas companies believe that the deregulation is proceeding too slowly and that the current regulatory system discourages risk-taking by energy firms.

The Australian Pipeline Industry Association (APIA) has criticized the slow progress being made on a number of energy reforms. This creates uncertainty amongst investors and, as a result, says APIA, the investment needed to improve Australia’s pipeline infrastructure is not being provided quickly enough. Most parties agree that the country’s largely separate regional gas markets need to be connected and integrated with one another as far as possible; but progress on this has been very slow.

Some groups nevertheless worry that deregulating gas pipelines will entrench the power of monopoly owners. Pipelines do not always exist as parallel competing routes. Third party access on competitive terms can introduce an element of competition, but a draft report issued last year by Australia’s Productivity Commission suggested that pipeline companies need a period of up to 25 years without a fully competitive system of access in order to ensure them a rate of return that is attractive enough to make them build the pipeline in the first place. Too much regulation, it is argued, can push internal rates of return below the threshold that the developer requires in order to proceed with the project.

Pipeline progress

Whilst the arguments continue over pipeline deregulation, some companies at least continue to expand their operations. Australian Pipeline Trust (APT), which owns the trunk line that connects the Moomba gas field with Sydney, has recently bought stakes in two pipelines on the other side of the continent, in Western Australia.

APT faces a problem common to other pipeline companies serving older gas fields: there are doubts whether Moomba has sufficient recoverable reserves remaining to meet long term supply commitments. There is also a competing pipeline serving the Moomba field.

Western Australia is the home of most of the continent’s upstream gas activity and its pipelines have attracted considerable interest from outside the state. The recent sale of a 60% shareholding of a line from Dampier to Bunbury, which connects the offshore North West Shelf with the city of Perth, drew bids from companies such as APT, and Hong Kong’s Cheung Kong Infrastructure. In the end, however, the line’s administrators named a consortium that included Perth’s largest gas retailer, Alinta, as preferred bidder.

The deal has brought the criticism that it entrenches Alinta’s position in the Perth region. The pipeline is to be separately regulated for 20 years, under an agreement with the Australian Competition and Consumer Commission (ACCC), but some details about how the regulation will work over the long term remain unclear. In the meantime, some commentators have expressed the view that consumers will end up paying more for their gas as a result of the deal.

More production

Things appear to be much less complicated in the upstream sector. There, gas discoveries continue to be reported at a gratifying rate. Most of the activity is offshore, but some interesting finds are being reported on land.

In Northern Territory, Woodside Petroleum has just reported a ‘substantial’ new find next to its Blacktip field. Northern Territory is currently supplied by two declining fields, Palm Valley and Mereenie, and is remote from the country’s other major gas-producing areas. Woodside’s new find, named Polkadot, could be developed in conjunction with Blacktip to serve the rapidly growing industrial market in and around Darwin, which includes power stations and aluminium production.

Whilst companies continue to report interesting finds onshore, most company interest is centred on the continental shelf around Western Australia and Northern Territory. One company, Santos, recently sold most of its onshore acreage in the Otway Basin, which supplies gas to the state of Victoria, in order to concentrate on larger fields in the Timor Sea, which lies to the north of Western Australia. Santos is already a partner with ConocoPhillips in the Bayu-Undan gas and condensate field in the Timor Sea. The two companies recently announced another venture in the Timor Sea, known as Caldita. Gas from these areas will be exported as liquefied natural gas (LNG) from a terminal now being built at Darwin.

More LNG

Australian LNG is benefiting hugely from the rapid growth in gas demand in Japan, China and other parts of East Asia (see ‘Focus’). Recently, a potential new market has emerged in the shape of New Zealand, where the country’s largest offshore gas field, Maui, is in decline. New Zealand might require up to 270 mn cfd of LNG in future.

Woodside Petroleum is expanding its North West Shelf LNG terminal to allow it to handle 1.6 bn cfd. The government recently approved a 270 mn cfd LNG terminal to serve the Tassie Shoals off the northern coast. The Darwin LNG terminal is designed to handle 400 mn cfd initially. Meanwhile, ChevronTexaco is planning a terminal on Barrow Island, Western Australia, to serve the Gorgon and other fields. The next project may well be BHP Billiton’s and ExxonMobil’s Scarborough gas field, west of the North West Shelf. The field’s commercial potential has yet to be established, but BHP is talking of future LNG exports.

LOOKING AHEAD

Thai demand revival helps downstream sector

This year’s high prices are expected to depress demand for oil, especially in developing countries. One developing country where this is not happening, according to OET’s statistics, is Thailand. Demand during the second quarter of 2004 was nearly 6% above year-earlier levels, at 913,000 bpd (see Table 10.2d). This represents a growth rate similar to that seen in the boom years of the 1990s before the financial and economic crises of 1997. The revival in demand should please Thailand’s refiners, who have been struggling with overcapacity. It will, on the other hand, need to continue for several years if the downstream sector is to recover fully from the recent lean years.

Soaring demand

Demand this year has been largely driven by transport fuels, though rising electricity consumption has helped increase the use of heavy fuel oil as well. A sharp rise in the number of motor vehicles has boosted demand for gasoline and diesel, whilst a revival in tourism has led to an increase in the consumption of jet fuel.

This should all come as good news for the refinery sector. Thailand has a surplus of capacity and some of its refiners have high debt levels. Low demand led to the temporary closure of one refinery, a 70,000 bpd condensate splitter, but the recent revival in demand has allowed it to reopen.

The country’s largest refiner is the Petroleum Authority of Thailand (PTT), which has shareholdings in four of the country’s seven refineries (see Table E). PTT owns 100% of the Rayong Refinery Company, following its recent purchase of Shell’s stake in the original joint-venture (see ‘The Month in Brief’, September 2004), and 36% of the Petroleum Refining Company, a joint venture with ChevronTexaco’s Caltex unit. In addition to the above, the Thai national oil company owns 50% of Thai Oil’s Sri Racha refinery and 24% of Bangchak Petroleum.

Table E
Thailand: Refining capacity, 2004

Company	Refinery	Capacity
		(th bpd)
Thai Oil	Sri Racha	220
TPI	Rayong	215
Bangchak Petroleum	Bangchak	120
Star Petroleum	Rayong	150
PTT	Rayong	145
Esso	Sri Racha	145
TPI	Rayong	70
Total		1,065

Source: Company data.

Some of the refineries in which PTT has an interest are burdened by high levels of debt. Moreover, until fairly recently, some of its refineries operated at suboptimal levels as a result of lower than anticipated demand growth. The two joint-venture refineries at Mab Ta Phud in the province of Rayong were built in the expectation of high levels of demand growth through the 1990s and beyond. Shell has now sold its share of the Rayong Refinery Company to PTT, which has in turn proposed a merger with the remaining joint-venture, Star Petroleum, which occupies the site adjacent. The aim of the deal is to achieve economies of scale and thereby reduce operating costs. The new company would be owned 50-50 by PTT and ChevronTexaco. A decision on the merger is due in early 2005.

The recent revival in oil demand may tempt the Thais to consider refinery expansion once more. There have been various proposals over the years for a worldscale refinery in the south of the country, on the isthmus of Kra. The aim of such a refinery would be to supply mainly the export market, especially China. Allied to the proposal for a refinery in the south was a plan to construct a crude oil pipeline across the isthmus providing an alternative route from the Persian Gulf to East Asia to those via the crowded and pirate-infested sea-lanes through the Indonesian archipelago.

Petrochemical progress

Thailand’s economic recovery has prompted the construction of a large number of petrochemical units. Many are focused on domestic demand, including new industries, such as motor car manufacturing, which consumes large amounts of plastics.

PTT is a major player in the Thai petrochemical industry through shareholdings in various companies. Its olefins business is centred on Thai Olefins Company (TOC) and the National Petrochemicals Corporation (NPC). TOC is in the final stages of raising its ethylene capacity from 385,000 t/y to 700,000 t/y. NPC meanwhile is increasing its ethylene capacity by 23,000 t/y to 460,000 t/y and building a 250,000 t/y unit to make high density polyethylene (HDPE).

PTT also owns part of Aromatics Thailand (ATC), which recently completed a programme to expand production of paraxylene, benzene and toluene, with further increases planned for paraxylene and benzene. Benzene capacity is due to rise 42% to 467,000 t/y, while paraxylene will go up by 26% to 495,000 t/y. Completion in both instances is scheduled for 2005.

The olefins and aromatics industries provide an important outlet for PTT’s production of ethane, liquefied petroleum gas (LPG) and naphtha. To some extent, the growth of Thailand’s petrochemical industry has been feedstock-driven. PTT has found itself with surplus ethane and LPG from its gas production. A regional surplus of gas liquids also prompted Thai Petrochemical Industries (TPI) to establish an integrated refining and petrochemicals business. This year’s revival in demand should help all the country’s refiners and petrochemical producers, though it will need to continue much longer if some of the debt-ridden firms are to survive.