ASIAN GAS PROSPECTS-1: Russian Far East natural gas searches for a home

March 5, 2001
Development of the Russian Far East's enormous energy potential has long been a topic of vast (and often) under-informed speculation.

About this series
This article is the first of two prepared as part of an energy study on Japanese energy security for the James A. Baker III Institute for Public Policy, Houston, with support from the Center for International Political Economy, New York.

Development of the Russian Far East's enormous energy potential has long been a topic of vast (and often) under-informed speculation.

Everything in the scale of Russian Far East developments is big-reserves, distances, climates, problems, potential gains, costs, and long-term effects on Asia's gas-importing markets.

The enormous numbers bandied about in gas-development projects in the Russian Far East make it necessary to narrow the possibilities to the basic parameters of gas development and how those fundamentals affect Russian Far East project proposals.

Japanese commercial interest in Sakhalin was revived in the 1990s, resulting in two of three Sakhalin production-sharing agreements (PSAs) under current implementation.

The three existing programs include: Sakhalin-I, led by Exxon Corp. (now ExxonMobil Corp.); Sakhalin-II, led by Royal Dutch/Shelli, and Sakhalin-III, led by Mobil Corp. (now ExxonMobil).

A provisional PSA development, Sakhalin-IV, which would also be led by ExxonMobil, still must be fully approved by the Russian government.

Japanese involvement

Japanese interests in Sakhalin I and II are substantial and, as Sakhalin III and IV progress, Japanese companies will likely farm into these projects.

Japanese involvement with Sakhalin-I is under the umbrella of the older but reorganized Sakhalin Oil Development Corp. Ltd. (Sodeco) consortium, held 42.9% by Japan National Oil Corp. (JNOC), with the majority share split among 13 Japanese companies.

Despite a 30% share in the project, Sodeco is generally a passive partner in decision-making for this project. The consortium consists of a range of companies-utilities, trading houses, and refiners.

Japanese participation in Sakhalin-II consists of shareholdings by Mitsui & Co. Ltd. (25%) and Mitsubishi Corp. (20%). These Japanese companies originally allowed Shell and Marathon Oil Co. to take the lead in field development, with Shell also shouldering the burden of planning for gas exports.

With Marathon's withdrawal from the Sakhalin-II group in mid-2000, Shell is now the lead company on both ends of the development, acting as field operator (now with 55%) and overseeing LNG plant design and construction.

Yet it should be noted that both Mitsui and Mitsubishi are major powers in Japanese LNG, and they will take the lead in attempting to sell Sakhalin LNG in their home market. Both companies have shown at least limited interest in expanding their presence in the domestic gas sector.

Sakhalin-III currently has no Japanese participation and consists of ExxonMobil, Texaco Inc., and Russian companies.

It should be noted that two very basic factors shape all Sakhalin hydrocarbon developments.

The first is that primary development will be for the Japanese market. To the extent that gas exports to South Korea emerge over this decade at all, they are likely to supplement a Japanese-targeted customer baseload.

Moreover, liquids sales from the Russian fields will be handled before gas sales. This is because sales of crude and condensate allow for a quick buildup of revenue flow for multibillion dollar projects, easing the financial strain on development consortia, until first-gas sales are made.

This is true whether in reference to a Mideast-Persian Gulf gas pipeline project or an Asia-Pacific LNG development. Because most "oil finds" in the Russian Far East are usually combinations of oil and associated gas, the latter often containing substantial volumes of recoverable condensate, the dictum will be followed-both Shell in Sakhalin-II and ExxonMobil in Sakhalin-I have concentrated initially on production of liquids.

That said, the second principle comes into play, that while liquids development comes first, there must be gas development and exports to make any of these projects work commercially in the longer run.

The reason is simple: There exists, even based on our limited current knowledge, far more gas than liquids in Sakhalin and the Russian Far East in general. The presence of NGLs, including condensate, in gas reserves can make a good project even more profitable, but they cannot make an uneconomical gas project good.

The basic gas economics must be solid for a project to proceed. Condensate is a byproduct of gas production and gas sales come first.

As it stands now, only Japan has sufficient current gas-demand baseload and the ability to expand that quickly in the medium term (3-5 years) to provide the commercial support to underpin a Russian pipeline export project.

Japan must be also considered as a necessary demand support for any LNG project because LNG hopes are pinned on the island of Sakhalin, on the doorstep of Hokkaido, the northernmost of the Japanese home islands.

The natural gas resources of the Sakhalin Islands area compare favorably with other substantial regional natural gas suppliers.

Even at this early stage, preliminary estimates indicate that proven and probable gas reserves in Sakhalin could be as high as 50-65 tcf. By comparison, Indonesia, the world's largest LNG exporter, has proven reserves of around 82 tcf.

The gas resources in other Eastern Russian areas are more distant to markets. Yakutia is thought to hold an additional 35.3 tcf, while the Kovyktinskoye field in Irkutsk is estimated to have possible reserves of 52-105 tcf, according to Washington-based Planecon Inc.

These latter deposits, while large, may not be enough to encourage the massive investment needed to bring them to market, whether west to Europe or south and east to Northeast Asia.

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Tables 1 and 2 outline the natural gas potential of the Russian Far East. Table 1 shows the estimated recoverable gas, oil, and condensate reserves of the region. Table 2 outlines in more detail the reserves and production outlook for specific Sakhalin projects.

Markets

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Only three potential markets can be reached by Russian Far East developments via pipeline: China, South Korea, and Japan. The latter market still dwarfs the potential of the other two despite a long-running economic recession in Japan and a near decade of breakneck demand growth in the other two countries.

Japan remains the region's largest single gas-consumption market.

In 1998, Tokyo accounted for nearly 28% of the region's total gas consumption of 9.47 tcf or 25.94 bcfd. When only marketed-gas sales are considered (excluding gas used for exploration or oil field operations), Japan accounted for more than a third of all gas sales in Asia Pacific.

In that same year, Japan's LNG imports accounted for 55.7% of all LNG trade and more than 75% of regional LNG demand, and despite recession, Japan's LNG import rose some 4.7% in 1999.

A single company, Tokyo Electric Co., imports more LNG than either of Asia's two other LNG markets, South Korea and Taiwan. While Tokyo's relative "weight" in gas consumption has decreased as most of Asia enjoyed a near-decade of fast growth, it is important to remember that while Japan may no longer be the only "game in town," it certainly remains the most important single buyers' market.

Regulatory stranglehold

Neither China nor South Korea, at least in this decade, can provide a sufficient market for pipeline imports nor broad enough commercial support to jump-start any Russian Far East pipeline project.

While Beijing appears to be interested in importing energy supplies from the Russian Far East, it remains to be seen whether this effort will make commercial, or even political, sense.

The question of Chinese investment in Russian gas begs the related question of why China would prefer to invest in distant Russian supply before first exploiting its own substantial domestic gas reserves.

Many observers of Sino-Russian gas cooperation have not addressed the basic problems that have so far hampered gas development within China.

The most fundamental problem is that the Chinese natural gas market remains bound by a host of government regulations, including near total price controls for gas production, transportation, and wholesale and retail sales.

While China National Offshore Oil Co. (CNOOC), which produces gas offshore and links independent power production (IPP) projects, remains outside this all-encompassing web of government regulations, China National Petroleum Co. (CNPC), which controls most of the Chinese gas reserves and most infrastructure in the northern and western sections of China, remains bound.

With a wellhead sales price of slightly more than $0.50/MMbtu, it makes little sense for CNPC actively to search for gas, develop finds, or build the necessary transmission infrastructure to bring gas to market.

Investments in the gas sector have been made grudgingly and at a rate that ensures that development of a national gas market will be delayed until the very end of this decade, or perhaps later.

China's gas-market woes spring not from the lack of a potential domestic gas-reserve base, but from structural and regulatory constraints. Until price decontrol is introduced on a national basis, gas development will continue to lag.

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A large-scale project in Sichuan province, funded in part by the World Bank, aims to overhaul and expand the provincial gas transmission and reticulation system, as well as develop new gas finds in the western half of the region. The quid-pro-quo is that Sichuan first and the country as a whole later will gradually bring gas-sales prices in line with world levels.

Although such deregulation is under implementation in Sichuan, there are few signs that the central government is willing to free gas prices across China.

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And until that occurs, Chinese gas development on a national scale will lag: natural gas in 1999 accounted for roughly 2.5% of China's base energy mix, while it averages nearly 9.1% in Asia Pacific.

Chinese infrastructure

Currently, China operates only a handful of gas-transmission lines and has only just begun to build urban reticulation in major cities.

Recent statements by officials of the State Development Planning Commission confirm national support and funding for two major transmission lines: the Tarim basin to Shanghai trunkline, which is currently being built in stages, and the less ambitious Chongqing-Wuhan transmission line, utilizing newly developed gas reserves in Sichuan.

The country's first major urban gasification program, targeting Beijing (and originally intended to reduce air pollution if China had won the right to host the 2000 Olympics Games) is 2-3 years behind schedule, despite the completion of a gas trunkline by 1998 providing supply from the Shaanxi, Gansu, and Shanxi fields to the west of the capital.

The lag in completing distribution pipes within the city, as well as pumping and metering stations, has kept the capital's gas use at a minimum, despite gas availability. Bitter bickering has broken out among city, provincial, and national governments as to who will fund the program's completion.

On a national scale, the same problem arises: The central government can order the construction of gas infrastructure but often has been unwilling to fund it.

Who then pays? The municipal, provincial, or central governments? The newly established city gas companies? Or, the national integrated oil and gas companies, such as CNPC and China National Petrochemical Corp. (Sinopec)?

What answer ultimately emerges will have major ramifications; the bill for establishing a basic national gas-transport network, as well as gas distribution in major cities, will run to tens of billions of dollars over this decade.

Further limiting the Chinese market for Russian gas imports is the prospect that LNG will supply southern China. The central planning authorities have authorized the import of LNG, with one receiving terminal planned for Guangdong province in the south and another in the eastern seaboard province of Jiangsu, north of Shanghai.

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While no LNG exporter has yet concluded an agreement with Chinese buyers, Malaysia, Indonesia, Australia, Oman, and Qatar are all competing for a foothold in the emerging Chinese LNG market.

It is likely that first imports will begin by 2005 or shortly thereafter at one or both proposed terminals and quickly build to an initial 5-8 million metric tonnes/year of LNG, representing roughly 664 MMcfd to 1 bcfd of clean, stripped, dry gas supply. (Feed gas volumes can range higher by as much as 20%.)

While it is possible that an LNG project based on Sakhalin could in the future export cargoes to these coastal provinces, the LNG initiative cuts off these regions as areas of potential gas demand for pipeline imports.

This means that an export pipeline, which would have to begin at a minimum of 1-2 bcfd of supply capacity, would not have the potential buying interest of a major segment of the Chinese domestic market.

Korean picture

China, therefore, is no easy 'Shangri-La' market for Russian pipeline exports, at least not in the medium term.

The problems to overcome are clear: sector over-regulation, price controls, the need to build national gas transportation, as well as specific urban distribution networks, and potential competition from both domestic production as well as imported LNG.

Seoul poses a similar number of problems as a market for Russian pipeline gas exports, though it can always serve (at minimum) as a secondary market for Sakhalin LNG sales.

To begin, although South Korea has substantial gas infrastructure in place, including a national transmission network and two (soon to be three) LNG receiving terminals, the overall size of the South Korean market is too small to support a pipeline export market alone.

In 1998 (a peak gas-demand year for Seoul), gas consumption totaled nearly 1.5 bcfd, less than China's 1.87 bcfd and less than a quarter of Japan's 6.3 bcfd in gas use.

In 1999, gas use declined, although rebounding sharply last year.

Even under the unlikely scenario that South Korea backed out half of its current LNG-purchase commitments and saw gas demand expand by 8% annually through 2005, the national market would be hard pressed to absorb 1-2 bcfd of pipeline gas by mid-decade.

The second difficulty, and most obvious geopolitical obstacle to the easiest and least expensive overland pipeline route, is the continued existence of a hostile and potentially unstable North Korea.

While a pipeline can be routed to South Korea from China in the west or Japan in the East, either route would add an additional cost in building an offshore pipeline segment and would be vulnerable to sabotage.

A further potential obstacle to the sales of Russian gas to South Korea is the poor financial health of South Korean trading houses as well as energy-sector companies. Many of these trading houses have considerable debt on their books and may be reluctant to take on a capital-intensive pipeline investment.

Meanwhile, Korea Gas Corp. (Kogas), the country's sole gas importer, is in the middle of a government-mandated reorganization.

If Sakhalin-II finally commissions an LNG export facility, as currently planned, South Korea would be a likely buyer, though not necessarily providing sufficient demand to support a project on its own. Japan, however, remains the focus of Sakhalin II LNG marketing.

Japan, Sakhalin linked

The "tyranny of distance" in gas markets, combined with commercial pressures, yields an inescapable conclusion of Japan as buyer and Sakhalin as seller among the options currently in play for Russian gas, at least in the medium term.

If even a limited national Japanese natural gas pipeline system is completed by 2010, Japanese buyers could have a number of choices for potential gas suppliers, but sales from Sakhalin, either by pipeline or LNG, will still have a substantial capital cost advantage over many other suppliers.

Sakhalin gas is the most economical by pipeline, reaching Japan for the equivalent cost of $2-2.80/MMbtu, compared with Yakutia gas at $2.50-3.70/MMbtu or Irkutsk gas at $2.30-3.60/MMbtu.

Sakhalin LNG costs are moderately competitive at the equivalent of $2.25/MMbtu, only slightly more expensive than the $1.90/MMbtu costs for shipment from Bontang LNG (Indonesia) and the $2.15/ MMbtu for shipments from Australia's Northwest Shelf.

By comparison, minimal delivered gas costs from Qatar, taking into account the comparable capital costs, would be $2.45/MMbtu. Actual market-LNG import prices in 1999 were generally higher than these estimated levels for Sakhalin costs of $2.25-2.80/MMbtu, ranging between $2.91/MMbtu for supplies from Abu Dhabi to $3.31/MMbtu from Arun (Indonesia), according to World Gas Intelligence.

The timing is right for Japanese companies to press for cheaper LNG terms. "Non-economic factors" will never completely disappear; for example, strict adherence to the Kyoto accords will shape Japanese energy choices in the future as much as the bugaboo of energy security did the past, but increasingly, market forces have come to matter.

The trend to search out and acquire "lowest cost" supply, particularly for natural gas, is being driven by a series of profound shifts in the Japanese economy.

One major force for Japanese companies to pick lowest cost supply is that the domestic market will no longer accept, passively and without question, some of the highest utility rates in the world. Increasingly, utilities in Japan must re-examine, in the most basic way, how they do business-including lowering costs and financing capital improvements.

Japan's long-running recession, after the "Bubble Economy" burst, has had another unforeseen consequence. It has opened the door to sector deregulation that is needed to spur efficiency and economic growth, and free Japan from its lingering downturn.

Both business and government have embraced utilities' deregulation, although enthusiasm for it varies widely. Recently, large commercial power companies were given the right to choose suppliers; smaller power consumers will follow by 2001.

Similarly, certain, larger volume gas buyers can now pick their supplier. The government has guaranteed third-party access to distribution systems.

The new era of low-cost supply has also introduced competition not only on a geographic basis, but in cross sales, i.e., power companies selling town gas and town-gas companies selling electricity.

Further, the opening of the power sector to nonpower companies, through IPP projects, has not only attracted interest from trading houses (traditionally the conduit for gas supplies to utilities), but also from foreign companies such as Enron Corp., as well as such oil and gas companies as Shell, ExxonMobil, Chevron Corp., and Texaco.

Competition will rise and pressure for lower gas prices will increase, as new companies enter traditionally closed sectors.

The growing pressure for lowest-cost gas supply has been underscored by the new moves towards the convergence of the power and gas industries. This trend, well established in the US, growing rapidly in Europe, and emerging now in Asia-Pacific, is based on the consideration of gas and power as integrated entities.

The idea of "convergence" is that gas supply cannot be considered alone, but only in relationship to power generation, as gas turbines can compete effectively on commercial and environmental grounds against fuels in this sector.

Power represents the largest single use of natural gas in most economies and in almost all Asia-Pacific gas markets. On this basis, convergence advocates argue, the push for lower-cost natural gas will come from those companies which attempt to secure lowest cost base fuel, in an effort to compete efficiently against traditional power utilities.

While still in its preliminary stage in Japan, convergence will provide a powerful pressure to seek new methods of gas pricing and a continuing effort to lower gas import price levels.

The author

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Al Troner, based in Seattle, is managing director of Asia Pacific Energy Consulting (APEC), a small Kuala Lumpur-based consultancy established in 1995. Since 1984, he has worked in Asia's energy sector, establishing Dow Jones/Telerate's regional energy services that year and returning to Singapore in 1989 to found and direct Petroleum Intelligence Weekly's Asia-Pacific bureau.

From 1987-1989, Troner worked as a research assistant for the energy group of the East West Center. He received a BA from the State University of New York at Stony Brook and an MA from the University of Hawaii.