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Indonesia weighs up energy conundrum

The country is struggling to attract investment despite being Southeast Asia's largest oil producer

Indonesia is Southeast Asia’s largest oil producer and has plans to increase production to more than 1 million barrels a day (b/d). It is also the world’s third-largest producer of liquefied natural gas (LNG). But the net-oil importer has struggled to reverse declining oil production as it fails to attract much needed investment.

The former Opec member’s oil output has declined over the last decade as production matured and the reserve replacement rate slowed. Total crude production stood at 942,000 b/d in 2011, a drop of 32% since 2001 and just shy of the targeted 945,000 b/d, according to the BP Statistical Review of World Energy. This year’s production target is 930,000 b/d. This is expected to drop to 900,000 b/d in 2013.

At the end of 2011 Indonesia held proved oil reserves of 4 billion barrels, down from 5.9bn barrels at the end of 1991. A diverse range of geological basins offer sizeable hydrocarbon potential. But of the estimated 128 oil basins, only 38 have been extensively explored.

Oil production dropped below 1m b/d in 2006 and ever since the government has been pushing to hit this threshold again. It has expressed hopes to become a net oil exporter again by 2020. But bureaucratic delays and regulatory uncertainty have hindered progress so far.

A large part of the production push hinges on ExxonMobil’s Cepu project, in Java, which is expected to produce 165,000 b/d at full production by late 2013. But production ramp up could be several years behind schedule and this field alone will not stem falling output.

Most oil production comes from basins of western Indonesia, but with few significant oil discoveries in the last 10 years, Jakarta is focusing on developing reserves in the nation’s eastern frontiers and deep-waters.

Normally the country offers an oil split of 85-15 in its concession agreements, but Jakarta is now offering as much as a 60-40 split for frontier areas or deep-water projects. For gas, contractors are given a 70-30 split, but 60-40 is offered for difficult reserves. With depletion acceleration at an average of 12% per year, new exploration agreements are essential.

Exploration in eastern Indonesia’s frontier basins over the past 10 years has been disappointing, with just four discoveries recording reserves greater than 1 trillion cubic feet (cf). The lack of nearby gas markets means that big gas discoveries outside Java and Sumatra will likely be developed as LNG, notes consultancy Wood Mackenzie.

While oil production has declined, more gas has been discovered and the country’s proven gas reserves are continuing to rise. Conventional gas infrastructure is being developed, while the emergence of large unconventional gas reserves has sparked interest in the development of these new resources.

Indonesia has some of the world’s largest conventional gas reserves at around 3 trillion cubic metres (cm). Production stood at 75.6bn cm in 2011, down 7.8% from 2010 levels, but has otherwise been growing for more than a decade.

However, the country’s historical preference to develop gas fields as LNG projects targeting export markets and its poor internal distribution network means Indonesia is struggling to keep up with domestic gas consumption, which totalled 37.9bn cm in 2011, down slightly from a high of 40.3bn cm in 2010.

The archipelago has several discrete gas markets. West Java is the largest and is starting to import increasing volumes of LNG to meet ballooning demand. While gas price increases in Java will have little effect on exploration activity in eastern Indonesia, it boosts the chances that smaller discoveries in the more mature basins of Java and Sumatra will be developed, according to Wood Mackenzie.

Since mid-2011, the Indonesian government has renegotiated a number of legacy gas contracts, increasing prices by up to 200%, to encourage more developments and avoid a supply crunch.

The government hopes higher prices will encourage exploration to meet supply shortfalls in West Java.

Regulators have allowed gas prices to double from levels around $2-3 per 1000 cf seen over the past 10 years, to $6-7/’000 cf this year.

Higher gas prices will possibly encourage the development of technically challenging discoveries, previously deemed uneconomical.

There will also be a much higher chance that investors will look at unconventional sources, such as coal-bed methane (CBM) and shale gas.

But there are challenges for the government. Businesses are already feeling the pinch of rising prices and it is not yet clear if unconventional sources can be economically developed.

If the unconventional sources do not materialize, then West Java will need to buy more LNG or burn more coal. But if West Java is forced to buy more LNG at international prices, currently around $14/m British thermal units, then there will be a large price gap which could lead to social and economic problems.

West Java currently imports small volumes of LNG from Indonesia’s Bontang export plant as part of a domestic market obligation to help meet rising demand.

In the longer term, the government needs to raise prices further to encourage development, but faces resistance to higher prices from end-users. Analysts see an upward trend in pricing but say full market liberalisation is still some way off.

Indonesia’s CBM reserves are estimated to be 453 trillion cf, which is larger than the country’s estimated natural gas resource and ranks sixth in the world. But development of these unconventional basins has been slow to get started. CBM regulation is proving difficult as the resource is economically, environmentally and politically challenging.

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