Asia-Pacific gas projects hit the wall amid regional economic slump

Feb. 8, 1999
This liquefied petroleum gas storage depot in southern Thailand is part of a midstream gas sector in that country getting squeezed at both ends as a result of the Asian economic slump. Not only is the slump in Asian gas demand reducing potential supplies in the Asia-Pacific region, the petrochemical industry that would receive feedstocks from gas processing facilities also is mired in the doldrums. Photo courtesy of Petroleum Authority of Thailand. [44,244 bytes]
Gas processing complex at Rayong, Thailand, is part of a gas industry infrastructure in Thailand that had been booming until the economic downturn in Asia crimped gas demand and, consequently, regional gas expansion plans. Photo courtesy of Petroleum Authority of Thailand.
After more than a decade of robust economic growth and expansion that caused natural gas consumption to surge, the Asian economic crisis is squeezing every aspect of the Asia-Pacific gas sector, from exploration to downstream feedstock demand, imperiling a multitude of projects at various stages of development.

Major gas projects on the drawing boards for years have been suspended or shelved, and projects currently under way are urgently seeking long-term gas purchase contracts.

Even projects that have come on stream recently-or are close to the start-up stage-face difficulties getting buyers to honor the terms of purchase contracts signed during the boom years, when escalating demand was the accepted norm.

What had seemed a nascent boom in Asia-Pacific liquefied natural gas projects is already starting to fizzle (see table [60,866 bytes] and related article, p. 58).

It is difficult to overstate the effect of the economic debacle on Asia's gas industry. After a generation of 5-6%/year growth rates, Asian economies were estimated to have shrunk by 1.3% in 1998, according to Consensus Economics Inc. Most of the region is officially in recession-defined as gross domestic product having contracted for at least 2 consecutive quarters. And some economists are beginning to use an even less optimistic term: depression, defined as deflation coupled with severe and prolonged recession.

Gas demand slump

The effect of this economic malaise on Asian gas consumption has been predictable: Gas demand in Asia has grown this decade by 7.2%/year-the strongest growth rate worldwide-reaching 8 tcf last year, according to Petronas, the Malaysian state oil and gas company and the world's third largest gas exporter.

As a result of the economic slowdown, Asian natural gas demand is expected to remain flat for 1998 and then grow at only 4.4%/year to the end of the century and just 3.5%/year through 2010, according to Petronas estimates. Demand in the region by 2010 is now projected at 12 tcf, down from pre-crisis estimates of 16 tcf. Under the new projections, 16 tcf demand is not expected to arrive before 2014, Petronas predicts. This shortfall is having, and will continue to have, a devastating effect on planned projects.

It's all a far cry from a year ago, when economic expansion seemed likely to spur sizzling consumption growth for the foreseeable future (see chart [62,496 bytes]). Markets in Japan, South Korea, Taiwan, Thailand, India, and China were supposed to provide cash flow for a string of massive gas developments over the next several de-cades.

"It has been a totally unexpected fiasco," said one Asian industry executive.

"According to all the growth projections-by the national oil companies and power authorities and the energy economists-demand projections were always straight up. Unfortunately, in the real world, demand ebbs and flows-nothing is ever straight up."

The fact that low oil prices look to persist in the medium term is also not helping. Most gas agreements are linked to crude prices, making pricing accords difficult, at least for sellers, to agree to terms.

"There has been an unfortunate confluence between a demand downturn and low prices that is devastating operators' bottom lines and seriously affecting existing projects and those pretty far along in the design stage," said an executive with an operating company. "The fact is, there is a buyer's market out in Asia now, and gas is available from a number of sources. The competition for long-term gas contracts is vicious."

Japan, South Korea

Historically the two largest Asian buyers, Japan and South Korea, are seeing gas demand growth slacken for the first time since World War II.

Annual energy demand growth for Japan during 1998-2010 is projected to slow to 0.9% from 1.7% during 1985-97, according to government and private sector figures. Japan imports 2.114 bcfd, a figure that is expected to largely stay flat over the next several years.

As for South Korea, projections of gas consumption have declined, to 11.06 million metric tons for 1998 from an earlier forecast of 12.2 million tons for that year, according to the government. For 1999, the forecast of South Korean gas demand has been sliced to 12.96 million tons from 14.16 million tons.

The experience of Korean Gas Corp. (Kogas), South Korea's gas import company, best illustrates the situation. Kogas is confronting a major problem in deciding how to dispose of surplus liquefied natural gas being held in storage facilities.

Despite various efforts by Kogas to adjust imports and local consumption, the company has accumulated 800,000 tons of excess LNG and has run out of storage space.

Kogas originally projected its demand at 12.28 million tons for 1998-up from 11.11 million tons consumed in 1997-but the recession forced the company to cut it back to 10.89 million tons. Kogas has even threatened to vent the surplus gas into the atmosphere, because storage facilities are at capacity. As a consequence, the company is attempting to delay the schedule of imports and is currently seeking to renegotiate existing 15-20 year LNG contracts.

Kogas's major client, Korea Electric Power Corp. (Kepco), which accounts for almost half of LNG consumption in South Korea, suspended LNG power plant operations for awhile this year, cut supply purchases, and looks to reduce them further in 1999. In 1997, Kogas supplied 5.38 million tons of LNG to Kepco, but in 1998, it reduced volumes to 3.53 million tons.

The effects of the consumption slowdown and low prices have been profound on individual projects.

Utilities and national oil companies that have based their gas purchase contracts on outmoded, pre-crisis demand models are now either scurrying to renegotiate, if a deal was actually signed, or are driving a tough bargain in contract negotiations, if an arrangement has yet to be finalized. Projects with no firm purchase agreements but with development under way confront a difficult situation, indeed.

Natuna update

Undoubtedly the most capital-intensive casualty has been Indonesia's East Natuna project.

The largest gas field complex in Asia, East Natuna is in the South China Sea, 683 miles north of Jakarta and 140 miles northeast of Natuna Island. Discovered in 1970 by Italy's Agip SpA, the structure contains an estimated 46 tcf of reserves. The field is owned by a consortium led by a unit of Exxon Corp., the operator with a 50% interest; Mobil Corp. with 26%; and Indonesia's state-owned Pertamina with 24%.

Natuna's gas has a carbon dioxide content of about 71%.

Cost estimates for exploiting the field have been placed at more than $40 billion. The project calls for construction of at least 18 offshore platforms: 6 for drilling, 6 for treating, 4 for injection work, and 2 for staff quarters. The injection work is a major reason for the high cost estimates. The CO2 will need to be separated from the natural gas stream and reinjected into the ocean floor to avoid releasing large volumes of CO2 into the atmosphere.

As a result of the economic crisis, a major agreement with Thailand for Natuna gas supplies collapsed. In May 1997, Pertamina signed a memorandum of understanding with the Thai state petroleum company Petroleum Authority of Thailand (PTT), calling for PTT to purchase natural gas at an initial rate of 500 MMcfd starting in 2003 and increasing to 1 bcfd beginning in 2007.

The arrangement also had provisions for a 1,000-mile, subsea pipeline to transport the gas from the East Natuna fields to Thailand via Malaysian waters. In addition, PTT was to acquire a 12-15% stake in the East Natuna development project. However, PTT began to back away from the deal following the start of the Asian economic downturn. In November 1997, Pertamina and PTT reached an agreement to delay the start of the deal to 2007 from 2003. But few observers now believe the arrangement with PTT will ever materialize.

Apart from regional competition, Natuna faces tough competition from other developments within Indonesia. These possess less problematic gas and far lower development costs. An arrangement between Pertamina and Singapore's Sembawang Engineering & Construction Pte. Ltd. has been finalized. It calls for Sembawang to purchase 325 MMcfd of gas from the West Natuna gas fields, under development by a group led by Conoco Inc., for 22 years starting in 2000. This includes the construction of a $400 million, 300-mile subsea pipeline to move the gas from West Natuna to Singapore (see map, OGJ, Jan. 25, 1999, p. 44).

LNG projects

Also in Indonesia, ARCO's discovery of the massive new Tangguh gas field in the eastern province of Irian Jaya faces problems finding future customers.

The discovery was made on the onshore and offshore Wiriagar and Berau blocks in September 1997 and represents ARCO's largest gas discovery outside the U.S.

ARCO plans to spend up to $3 billion to develop Tangguh reserves, which are estimated at 13 tcf, with an additional 7 tcf of reserves possible. ARCO holds a 48% interest in the Berau block with partners Occidental Berau of Indonesia Inc. 22.856%, Nippon Oil Exploration 17.144%, and KG Berau Petroleum 12%. In the Wiriagar block, ARCO holds an 80% interest and KG Wiriagar Petroleum Ltd. 20%.

The discovery prompted ARCO and Pertamina to plan a multiple-train LNG plant. Production of 6 million tons/year of LNG is scheduled to commence in 2003.

While development plans for Tangguh are under way, industry analysts wonder where ARCO and Pertamina will be able to market the gas. Preliminary talks with LNG buyers in Japan, South Korea, and Taiwan are reportedly going nowhere.

Just to the north, in Malaysia, a similar situation exists with another major LNG project, LNG Tiga.

Finalizing sales accords for Malay- sia LNG Tiga, the third LNG facility at Bintulu, Sarawak, is proving difficult, and Petronas officials are already conceding privately that production will be cut back from the nameplate capacity of 6.8 million tons/year. Industry executives say Petronas will be fortunate to find any market at all in the medium term.

The two-train plant, a joint venture of Petronas 60%, Shell Gas Sdn. Bhd. 20%, and Nippon Oil Corp. 20%, is due to come on stream in 2001.

According to Petronas officials, construction of LNG Tiga is on schedule, and negotiations with several potential purchasers in South Korea and Japan were continuing late last year, but there seems scant doubt that the talks have bogged down.

In early 1996, the LNG Tiga consortium signed a letter of intent with Japan Petroleum Exploration Co. (Japex) to supply up to 1.5 million tons/year of LNG for 20 years, beginning in 2001, with carriers owned by Petronas Tankers. But no arrangement has been concluded. Other talks with Kogas are also inconclusive, and likely to remain so.

JDA dilemma

A similar quandary confronts the operators in the Joint Development Area (JDA) owned jointly by Malaysia and Thailand.

While development is proceeding apace, with costs now totaling $200 million to date, analysts are beginning to question where the market for the gas will be. In September, PTT announced that it was suspending plans to build a 186-mile pipeline that would deliver gas from the JDA to the southern Thailand city of Songkhla. While Petronas has publicly professed support for the JDA project, recently it has also displayed signs that it is getting cold feet.

PTT and Petronas signed an agreement in 1996 to purchase JDA gas at an initial rate of 600 MMcfd in 2000 and increasing to 1.5 bcfd by 2003. The gas was to be used to support a number of joint-venture projects in northern Malaysia and southern Thailand, such as a gas processing plant, power station, and industrial gas distribution system. However, with its pipeline project stalled, PTT is in the process of negotiating with Malaysian authorities to postpone the natural gas delivery date to 2002. Given Thailand's numerous sources of natural gas, many observers believe it will be at least a decade before the JDA gas is purchased.

"The Thais can't even meet their commitments purchasing Burmese gas (from the Gulf of Martaban off Myanmar), and (that) pipeline has already been completed," said one executive. "I don't see them being in any position to follow through on JDA purchases for a long time."

Petronas is in a similar position. Asian gas demand is down, paralleling the economic contraction. And sources of supply abound. Petronas executives also say that JDA gas purchases will be hard to justify, and if the economy fails to rebound at least moderately by the time production starts, they may have to be suspended. "It is something that will be considered very carefully indeed," one Petronas official said.

Viet-Malay project

Contract problems also may be delaying Phase II of the development of Block PM-3 in the Commercial Arrangement Area (CAA) between Malaysia and Viet Nam.

It was due to come on stream in 2000 with production of 250 MMcfd, but now Petronas is considering indefinitely suspending Phase II, industry sources said.

Five oil and gas fields-Bunga Kekwa, Bunga Raya, Bunga Pakma, Bunga Seroja, and Bunga Orkid-have been discovered on the block, but the geology is complex, and more than 100 discrete reservoirs have been identified. The CAA once comprised acreage claimed by Malaysia and Viet Nam but is now being developed under terms of a settlement reached in 1996.

Phase II was expected to yield at least 40,000 b/d of oil and condensate and 250 MMcfd of gas and was to come on stream in 2001. On the Malaysia side, the gas was to be piped 135 km to the Malaysian city of Kerteh to be processed and used as feedstock in three petrochemical projects being developed by Union Carbide Corp. Feedstock there will now be obtained from other sources.

"Petronas already has more oil and gas being produced than it can market and is looking at delaying future output until demand warrants," said a Petronas official.

Myanmar woes

Myanmar may be the region's worst casualty of the crisis. It was supposed to join the ranks of Asia's natural gas exporters in July with the inauguration of a $1 billion pipeline. But Thailand has reneged on one gas purchase agreement covering the Total-operated Yadana development, and a second development operated by London's Premier Oil plc is in jeopardy (OGJ, Nov. 16, 1998, p. 21).

With the start-up of Total-operated Yadana gas field in the Gulf of Martaban, Myanmar was supposed to begin earning regular foreign exchange currency for the first time in its history. According to terms of its contract with state-owned Myanma Oil & Gas Enterprise (MOGE), PTT was supposed to purchase 325 MMcfd of gas for 32 years commencing July 1, 1998. Output from Yadana was expected to rise to 550 MMcfd by August 1999.

To date, no gas from Yadana has been taken. Total and its partners within the Yadana gas consortium are insisting that PTT live up to the terms of its take-or-pay contract, and no negotiations are currently under way, according to Total's general manager for Myanmar, Michel Villard.

"All of the Yadana partners are keen to see the contract's terms honored, and that is really the end of the matter," Villard said.

All of the Yadana partners met with PTT in Rangoon in November to drive home the point that PTT is liable to pay for all gas contracted for, whether taken or not, he said.

Under terms of the contract, 65 MMcfd of gas was to be taken as of Aug. 1, 1998, building to 325 MMcfd by yearend.

PTT has attempted in previous talks to reduce the price and the amount of gas and has let it be known that it could declare force majeure, if necessary. Yadana field is held by Total 31.24%, Unocal Corp. 28.26%, PTT Exploration & Production (Pttep) 25.5%, and MOGE 15%.

But if Total is discouraged, Premier must be despondent. It appears highly unlikely that PTT will be able to take any gas from Premier's Yetagun gas project. Yetagun field, 270 km west of Thailand on Blocks M-12, M-13, and M-14 in the Gulf of Martaban, is due to begin supplying 200 MMcfd to Thailand in 2000 under a 30-year arrangement between PTT and the Yetagun consortium. The consortium is comprised of Premier Oil, MOGE, Petronas Carigali, Nippon Oil, and Pttep.

Despite the Yadana situation, Premier expects to get Yetagun proven reserves certified up to 2-3 tcf to support flow rates of 350-400 MMcfd, up from the current level of 1.2 tcf certified reserves for a 250 MMcfd flow rate. It is continuing to proceed with development, at last report. Engineering consulting firm DeGolyer & McNaughton is currently conducting the certification appraisal and should issue a final report by the end of first quarter 1999. Under terms of the Yetagun consortium's gas purchase contract, PTT is obliged to purchase gas up to volumes of 400 MMcfd if the estimate of field reserves exceeds 2 tcf. Premier has started laying a 24-in. pipeline from the field.

Aussie projects stumble

Australia's North West Shelf project, the largest operating gas development in the region, also is feeling the pinch from the Asian economic downturn.

A current $4 billion expansion project is scheduled to be commissioned in 2003 and would nearly double existing capacity to 14 million tons/year. The project includes onshore processing and offshore production facilities, a new fractionation train, new LNG storage tanks, and additional shipping for the project. Although the expansion program is going ahead, the pace of development has been significantly reduced. Its ultimate economic success depends largely on the commitment of Japanese and South Korean customers to increase future purchases and on the developers' ability to find new markets for the gas such as India, China, and other emerging markets.

In May 1998, Woodside Petroleum Pty. Ltd., operator for the North West Shelf group, announced that it expects to finalize a sales agreement with Japanese LNG buyers by second half 1999.

For its part, Shell Australia Ltd. is also pursuing an aggressive campaign to find markets in Japan for the gas. Shell has a one-sixth interest in the North West Shelf joint venture and owns 34.3% of joint-venture partner Woodside.

"Until I hear differently, the Japanese buyers from the North West Shelf, the traditional eight big utilities from Japan...are still anxious to buy the output from the expansion of the North West Shelf," Shell Australia CEO Roland Williams said. "As far as I am concerned, as one of the venturers on the North West Shelf, I am still going for 2003."

But no letter of intent has been signed with either Shell or Woodside for the expansion capacity, and the same buyers are known to be negotiating with Petronas and LNG Tiga. The North West Shelf project is an equal joint venture of Woodside, Shell, Chevron Corp., BHP Petroleum Pty. Ltd., British Petroleum plc, and Japan Australia LNG (a 50-50 joint venture of Japan's Mitsubishi Corp. and Mitsui & Co.)

Another massive Australian LNG project near the North West Shelf development, the Gorgon project-which was also set to start production in 2003-has been delayed as well.

Gorgon will have a maximum output of 8 million tons/year of LNG (equivalent to 390 bcf/year of natural gas), and a major development drilling program is scheduled to start this month. Partners in the project include Chevron, Texaco Inc., Mobil Corp., and Shell, collectively known as CTMS JV. The development program will commence as scheduled but at a reduced pace. Production from Gorgon will be set back at least 2 years, sources say.

China the exception

The single encouraging sign on the Asia-Pacific natural gas horizon is the continued growth of the Chinese gas market and its relative insulation from the current economic and demand downturn.

China has only recently begun to tap its reserves of natural gas, and major infrastructure investment will be needed to transport the gas to market. Natural gas currently accounts for just 2% of the country's total energy mix, compared with an average of 20-30% in developing countries. Gas demand is expected to increase to 6.5 tcf/year by 2020 from less than 1 tcf/year, making it Asia's largest consumer.

There is huge potential for foreign firms to invest in the emerging Chinese natural gas industry. Commercially recoverable reserves in China total 41 tcf, according to the government.

The potential for foreign participation in China's gas business is huge. All business sectors covering upstream, midstream, and downstream gas in China are aiming to attract foreign investment, which is expected to be enormous. For example, the development of a transnational gas pipeline from either Russia to China or from Central Asia to China alone would cost $8-10 billion.

"For the medium term, China is the only bright spot in an otherwise dismal scenario," said one gas executive.

Imports could consist of pipeline gas from Russia and Central Asia or LNG transported by carrier from the sluggish markets in Southeast Asia. For the Chinese authorities, the question of how to balance LNG and pipeline options will be one of the most difficult decisions for China's long-term positioning in the energy sector.

Most of its natural gas is currently produced onshore in Sichuan province, but China is targeting several large onshore and offshore fields for future development as a substitute for coal and oil. Beijing's current 5-year plan sets an annual production target of 25 billion cu m of natural gas (about 875 bcf) by 2000. By 2005, production is expected to exceed 1 tcf/year.

In the meantime, development work continues apace. Work is proceeding on the Pinghu natural gas field complex off Shanghai, and China has secured three loans from foreign banks totaling $319 million-$130 million from the Asian Development Bank, $120 million from the Japan Import-Export Bank, and $69 million from the European Investment Bank. When completed in first quarter 1999, the project should supply 42 MMcfd of gas to Shanghai.

Elsewhere on the offshore front, China National Offshore Oil Corp. (Cnooc) is expanding development of China's largest offshore gas field, the 3-tcf Yacheng 13-1. The project-a joint venture of Cnooc, ARCO (operator), and Kuwait Foreign Petroleum Exploration Corp.-came on stream in 1996 and supplies gas via subsea pipelines to Hainan Island and to a power station in Hong Kong.

Located near Yacheng 13-1 and with reserves estimated at 2.5 tcf, Dongfang 1-1 field is being developed by Cnooc and partners to supply feedstock to fertilizer plants on Hainan Island. Appraisal drilling has also started by ARCO in the Ledong gas fields in the South China Sea, just to the south of Hainan, despite protests by Viet Nam that part of the contract area is claimed by Hanoi.

Onshore, China's efforts focus on: rehabilitating and expanding productive capacity in the Sichuan fields; developing recently discovered fields in the Shaanxi-Gansu-Ningxia region of central-western China and in the far western Tarim basin of the Xinjiang Uygur Autonomous Region; and building pipelines to serve major cities. Several pipelines, including one from Xinjiang's Shanshan field to Urumqi and another from Shaanxi to Beijing, recently came on line.

Northeast Asian grid

Longer-term supply options for China include imports of LNG as early as 2002 and long-distance pipeline gas imports from Russia, helping to form the skeleton of what could become a vast Northeast Asia gas grid.

Preliminary discussions with Russia include plans for a pipeline that would extend to Japan via the Korean peninsula. During a state visit to Beijing in October 1998, Russian Prime Minister Sergei Kiriyenko discussed development cooperation and eventual sales of Russian gas.

The most advanced project involves Kovykta gas field, near Lake Baikal and Irkutsk in eastern Siberia, where an appraisal study is under way to establish if the field contains sufficient reserves to justify the huge costs such a massive pipeline would entail. Rusia Petroleum is the license holder and operator of Kovykta. Rusia is 60% owned by a joint venture of Russian company Sidanco 55% and BP 45%, with remaining interests held by the Irkutsk oblast (regional administration), power utility Irkutsk- energo, and South Korea's East Asia Gas.

Central to the project is the construction of a pipeline to transport the gas. Although details have yet to be worked out, it is expected that major upstream investors such as BP would take an interest. There have also been suggestions of sending spurs off the main pipeline to South Korea and Japan. The estimated cost of the line varies, from less than $6 billion to more than $12 billion, with much depending on the route and possible spur lines.

Long-term outlook rosier

While the fallout from the Asian economic crisis has been grim and great, the long-term development scenario is decidedly rosier.

Assuming the region's economy recovers by yearend 1999 or in early 2000, natural gas consumption should once again grow strongly, although not at the previously heady boom levels of just a couple of years ago. This will necessitate a sizable increase in upstream investment as well as in the region's gas infrastructure.

Some development will involve pipeline construction, much of which is still in early planning stages. In addition, substantial expansion of Asian LNG imports is anticipated.

But getting from here to there is the immediate problem. Demand forecasts, both regionally and in individual countries, have proven wildly inaccurate, and companies are being far more circumspect than they were before the economic crisis.

"The next 18 months or so will be very interesting, indeed," said one executive in the region. "But the industry is beginning to do the right things in terms of projects delays. While everyone believes the old boom days are gone forever, eventually we will see a sound recovery based on more realistic expectations."

Copyright 1999 Oil & Gas Journal. All Rights Reserved.