ENERGY NEWS

 Natural Gas Changes in Indonesia

Summary.  Indonesia’s natural gas industry is changing, affected by more competitive LNG markets, new pipeline exports, and increasing domestic gas demand. Rising power demands, fuel subsidy removals, and gas incentives in the 2001 Oil and Gas Law will drive increased use of gas domestically. Infrastructure limitations, financing issues, and regulatory uncertainty constrain gas development, however. Overcoming these constraints will balance Indonesia’s gas use, lower the cost of domestic energy, and be crucial to maintaining a stable power supply. Indonesia’s overall investment climate will determine the pace of future development. End summary.

Overview of Natural Gas Industry

Indonesia has between 170 and 180 trillion standard cubic feet (TSCF) of natural gas reserves, the twelfth largest in the world.  In 2002, the country produced 3.04 trillion cubic feet (TCF) of gas, number six in world gas production.  Indonesia currently supplies 26 percent of the world’s LNG.  LNG accounts for 54 percent of the country’s total natural gas production and is exported to Japan, South Korea and Taiwan.  Pipeline gas exports to Singapore began in 2001, reaching 82 BCF last year, with a new Sumatra-Singapore pipeline inaugurated last month. Revenues from gas exports are substantial -- $5.6 billion in 2002, or about 10 percent of Indonesia’s total export revenues.  Domestically, gas use comes primarily from fertilizer and petrochemical plants (34 percent) and the power industry (25 percent). Most of Indonesia’s gas comes from East Kalimantan (33 TCF in reserves) and Sumatra (29 TCF in reserves), but there are large uncommitted reserves in Papua (18 TCF) and other areas in the archipelago (46 TCF).  The industry is dominated by seven major companies, which account for 90 percent of all production (see para 19).

Times are Changing

3.  The nature of Indonesia’s gas industry is changing, however.  New LNG producers in Qatar, Australia, Russia, along with Malaysia, now challenge Indonesia’s leadership in the LNG market.  At the same time, a regional gas transmission network is developing, creating new gas markets and sources of revenue.  Domestically, the reduction of fuel subsidies ease fuel price distortions, making natural gas more competitive as a fuel alternative.  Gas should also play a significant role in meeting the country’s growing power demands.  Finally, the Oil and Gas Law of 2001 has streamlined the process for domestic gas supply sales and created a new domestic market obligation (DMO) for gas.  These changes create new opportunities in the domestic gas market, even as the global LNG market becomes more diversified.

Global LNG Market More Competitive

The global LNG market today faces declining production and transportation costs, excess supply, increased use of flexible contracts, and greater choice of suppliers.  The Japanese Institute of Energy Economics forecasts that LNG supplies in Asia will rise to 180 million metric tons per year (mmtpa) by 2010, outpacing demand by about 60 MT.  The benchmark prices that China negotiated in late 2002 with Australia and Indonesia (between $2.40-$3.00/mmbtu) for the Guangdong and Fujian LNG terminals confirmed the downward pressure on prices. Japan (the world’s largest LNG importer), whose import LNG prices for 2002 averaged $4.27/mmbtu, took particular notice.  As a result, Indonesia’s traditional LNG markets (Japan, South Korea and Taiwan) are eyeing new sources of LNG and seek to negotiate lower prices or at least shorter contracts.  (Note: Indonesia is not standing still, however.  It is currently seeking marketing opportunities in the western U.S. and Baja California with U.S. companies such as Marathon, Sempra and ChevronTexaco.) 

This comes at a difficult time for the Indonesian LNG industry.  The four-month month shutdown at ExxonMobil’s Aceh gas production facilities in 2001 disrupted LNG supplies for the first time in the country’s history, raising concerns about Indonesia’s ability to meet supply commitments.  Indonesia’s two LNG plants, Arun and Bontang, are producing 27 mmtpa, close to their capacity of 31.6 mmpta.  Thus, they lack spare capacity to supply potential new markets until BP’s Tangguh LNG plant in Papua (7 mmtpa) comes on line around 2007.  At the same time, Indonesia is trying to secure extensions from Japanese buyers for 12 mmtpa worth of contracts that will expire by 2011.  (Note: this will not be an easy sell.  Last month, Japan’s Tohoku Electric Power announced it would reduce its LNG contract with Indonesia by 2.3 mmtpa beginning in 2004.  One week earlier, Taiwanese utility Taipower chose Qatar’s Rasgas project over Tangguh for a $8.6 billion LNG contract.)

Pipeline Exports Jump

Pipeline exports of natural gas have offset in part the greater competition in LNG markets.  In 2001, Indonesia began exporting 325 mmcfd to Singapore via subsea pipeline from West Natuna under a 22-year contract.  Deliveries of natural gas to Malaysia’s Duyong gas platform began in August 2002, under a 20-year contract for 250 million cubic feet per day (mmcfd).  Gas sale revenues will likely total $14.2 billion over the life of both contracts.  This month, the South Sumatra-Singapore gas pipeline was completed; it will eventually supply 350 mmcfd over a 20-year contract.  Other export opportunities, such as a possible gas supply agreement between Pertamina and Malaysian national petroleum company Petronas to supply up to 300 mmcfd from South Sumatra to Malaysia are also under discussion.  Pipeline gas exports increased nearly 160 percent between 2001 and 2002, reaching 82 BCF and accounting for 5 percent of gas export volume.  

Lower Subsidies, New Laws Stimulate Domestic Demand

Given the increasingly competitive LNG market, both government and industry recognize the need to develop Indonesia’s potentially large domestic gas market.  Indonesia’s low utilization (compared with other developing countries), in part is due to reserves far from the demand centers in Java and Bali and limited infrastructure.   However, fuel subsidy reductions and legislative changes should stimulate domestic gas demand. The GOI slashed fuel subsidies from $7.6 billion in 2001 to a projected $1.6 billion in 2003, a 78 percent reduction.  (Note: this reduction is probably closer to 70 percent, following a partial rollback on fuel price hikes in January 2003).  According to Pertamina’s published fuel prices, this makes natural gas, at $2.50-$3.00/mmbtu, much more attractive than fuel oil ($4.85/mmbtu) and diesel ($5.53/mmbtu).        

The Oil and Gas Law of 2001 introduced other changes that will encourage domestic gas use.  The new law permits direct “free market” negotiations of gas contracts between buyer and seller, endorsed by the government.  In the past, production sharing contractors (PSCs) had to sell their gas to the state-owned petroleum company, Pertamina, which in turn sold the gas to the final buyer.  The law also establishes a domestic market obligation (DMO) for new PSCs, requiring them to dedicate up to 25 percent of gas production for the domestic market.  (Note: existing PSCs have requested that implementing regulations for the law clearly specify that the gas DMO only applies to new contracts).     

Growing Power Needs Will Drive Gas Demand

Power generation needs in Java and Bali will also spur growing domestic gas demand.  Over the last several years, peak power demand grew by an average of eight percent annually, while power capacity did increase. As a result, the actual reserve margin has declined from 16 percent in 2001 to a razor-thin 6 percent in 2003 (Note: desired reserve margins are normally between 25 and 30 percent).  According to a Cambridge Energy Research Associates (CERA) study, Indonesia needs over 10,000 megawatts of new capacity between 2008 and 2015 in order to prevent a long-term power crisis.  Much of that new capacity will be fueled by gas.  PLN plans to raise natural gas use by the power sector from 21 percent in 2002 to 40 percent by 2015.  By volume, this means an increase from 450 mmcfd last year to 1.7 billion cubic feet per day (bcfd) in 2015. 

Increasing gas consumption in the energy mix makes strong economic sense.  About 2700 MW of PLN’s gas turbine combined cycle (GTCC) plants in Java are running on fuel oil because of declining gas transmission and supply problems in East Java.  Petroleum fuels are expensive – about 6.2 cents per kilowatt hour (kwH), or 2.5 times more costly than gas.  PLN spends about $1.7 billion annually on oil-based fuels and estimates it can save up to $1 billion per year by switching to gas.  The switch, when coupled with the power utility’s plans to raise electricity tariffs to 7 cents/kwH, is an important element in restoring the financial health of Indonesia’s power industry (Note: PLN will likely post a loss of over $600 million for 2002). 

These incentives have raised domestic demand estimates and led to a number of new gas sales agreements.  In December 2002, PSCs and gas buyers signed 14 gas and LPG agreements under the direct gas marketing mechanism.  This month, gas producers signed 13 agreements worth $14 billion that will supply a total of 1.3 bcfd to power and petrochemical buyers.  PGN projects conservatively that between now and 2015, Indonesia’s domestic gas demand will increase by as much as 60 percent to 3.7 bcfd.   

Impediments to Domestic Gas Growth

Despite these changes spurring gas demand, impediments limit domestic gas growth.  The primary obstacles include a limited transmission and distribution system, financing limitations, and continued regulatory uncertainty.  Indonesia has an inadequate gas transmission and distribution network, with a total pipeline length of 2547 kilometers and a total capacity of 830 mmscfd.  State-owned gas utility PGN plans four more transmission projects to meet rising power sector demands for gas, as follows:                                      

In addition to these projects, the GOI may also build two LNG receiving terminals in West Java, to process and distribute gas from future LNG plants in Papua (Tangguh) and South Sulawesi (Donggi).  PGN is also investigating the feasibility of shipping compressed natural gas (CNG) over short to medium distances.   

Show Me The Money

Many producers require financial guarantees which pose another obstacle to domestic gas growth, according to industry observers.  In the power industry, a number of PSCs have requested that PLN provide standby letters of credit (SBLC) before investing in long-term gas supply agreements.  These gas producers, including U.S.-owned Amerada Hess and Australian-owned Santos, want PLN to guarantee around $800 million per year through letters of credit.  According to the Castle Group, a local business information firm, PLN’s credit availability with government-linked banks is only $550 million.  PLN has asked Bank Indonesia to exclude SBLCs from the legal lending limit in order to get around this obstacle.  (Note: some power analysts suggest that if PLN would permit higher returns on investment, companies would be willing to assume more of this risk themselves).

A recent Wood Mackenzie gas and power study concurs that financing limits growth in the domestic gas market. According to the study, most export credit agencies (ECAs) remain wary of large, domestic-oriented projects in Indonesia.  Future financing will be more successful for offshore-structured, export-oriented projects that can minimize political risk and generate dollar revenues.  Financing will also be more likely if companies like Pertamina, with hard currency offshore accounts, participate. 

Regulations Are Still Undefined

The current uncertain regulatory environment also limits domestic gas growth, because it inhibits the exploration and development of potential gas reserves.  Despite the DMO provisions in the 2001 Oil and Gas law to promote gas use, no accompanying upstream or downstream regulations have been issued to define the “rules of the game.”  Nor do regulations clearly define Pertamina’s new oil and gas role.  In addition to the regulatory uncertainty, doubts about contract sanctity, contract extensions, security, and taxation hurt the gas investment climate.  

ExxonMobil Indonesia (EMOI) offers two examples that gas investors will watch closely.  In one case, the GOI has required the company to increase gas supplies to national fertilizer projects in North Aceh, despite EMOI’s contractual commitments to supply LNG to South Korea and Japan.  Moreover, EMOI must supply this gas at subsidized prices (about $1.50 per mmbtu), less than half the $3.40/mmbtu LNG price.  The company is trying to complete a “value retention agreement” with the GOI in order to receive compensation for the difference in the two prices.  However, the GOI has indicated that EMOI must expect to “share the pain” involved in subsidizing these fertilizer projects.  

In the second case, EMOI and Pertamina have been at odds for over two years on extending the Cepu oil and gas technical assistance contract in East Java.  The current contract will expire in 2010, and EMOI is ready to invest nearly $3 billion in the lucrative project, which contains at least 600 million barrels of oil and 1.7 TCF of gas.  At peak production, Cepu would provide the GOI about $2 million per day in revenues and eliminate gas shortages in East Java.  However, the negotiations remain stalled over the size of Pertamina’s signing bonus (it seeks $400 million) and due to the opposition of nationalist-minded senior officials who would prefer that Indonesia develop the Cepu block.

The impact of this uncertainty weighs on the government.  Only eight new oil and gas contracts or extensions were signed in 2001 and two in 2002 (down from a high of 28 contracts in 1997).  This year, the GOI will tender 21 new oil and gas blocks, using more favorable revenue sharing terms than in the past – in some instances, raising the PSC share for gas from 30 percent to 45 percent.  So far, 13 companies (only one major) have submitted bids, for eight of those blocks.  According to the American Chamber of Commerce, gas blocks signed before 1971 still account for nearly 60 percent of Indonesia’s commercial reserves.  Blocks signed after 1990 account for only 14 percent of commercial reserves.

Gas Production and Use Statistics

Natural Gas Production (Million SCF)

Source: MIGAS

Marketed Natural Gas  (Million SCF)                                                             

Source: MIGAS

Comment

Though LNG exports will remain an important component of Indonesia’s gas marketing strategy, gas demand will increasingly shift toward domestic and regional markets. Power needs and cheaper, environmentally-friendly gas will drive this shift. Short-term growth in domestic use, as evidenced by the jump in gas supply agreements, will be relatively easy. However, long-term growth will depend on more complex regulatory, legal and security improvements – the overall investment climate. A turnaround in the investment climate is essential, not only to ease financing and encourage gas development, but to improve the country’s  economic health as well.                

###

 Trends | Reports | Energy | Coal | Petroleum | Investment