The dwindling fortunes of Indonesia’s energy outlook is forcing the country to take radical steps to change its future. Mriganka Jaipuriyar, in this week’s Oilgram News column At the Wellhead, reviews some of the shifts the country is taking to overcome earlier bureaucratic hurdles.
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As Indonesia, once an OPEC member and top LNG exporter, comes to terms with a new reality that awaits it — that in the next five years it is going to become a net importer of energy — the industry is urging the government to do what is necessary to kickstart the E&P engine.
Their demands essentially include cutting the number of permits required, streamlining bureaucracy, and making the fiscal regime more attractive.
Oil and gas contractors in Indonesia currently need 284 permits and have to go through 12 different ministries before they can get a project off the ground. It is therefore not surprising that it takes around 10 years to convert a discovery to production.
When ExxonMobil discovered the Arun field in Aceh, it took the company three years from discovery to production — the field was discovered in 1968 and produced first gas in 1971.
“Now it takes a minimum of seven to eight years. You know what has happened since — regulations!,” an ExxonMobil executive said in Jakarta last month.
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Italy’s Eni signed a PSC for the offshore Jangkrik gas project in 2002, but production is expected to start only in 2015. Similarly, Inpex signed a PSC for the Masela project in 1998, but first production is expected 20 years on in 2018. Indonesia has not seen a new project come onstream since 2008, when ExxonMobil brought onstream the Cepu field, and that too at rates far below the original target.
Lukman Mahfoedz, CEO of Indonesian oil and gas independent MedcoEnergi and president of the Indonesian Petroleum Association, said that the biggest impediment to the development of the country’s resources is the bureaucracy and the number of permits required.
The IPA has forecast that exploration activities must be three times the current level for Indonesia to see a significant difference in its reserves and production.
Indonesia’s crude oil output peaked at 1.6 million b/d in 1995 and has since fallen. It hovers around 800,000 b/d today. Gas production is expected to rise to 9.35 Bcf/d over the next few years from 8 Bcf/d today, but growth in demand is expected to outpace supply.
“We need to make the climate investor-friendly. So, we need to have a fiscal regime that attracts them. One of the important things in order to attract investors is not to burden them with too many things, such as taxes, upfront,” Mahfoedz said.
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The IPA has proposed that the government give authority to the energy ministry to discuss the fiscal regime and production split with investors. “Right now there are too many bodies involved,” he said.
A similar thought was echoed by A. Noviyanto, vice president of finance at Total E&P Indonesie.
“We [would like] coordination in the government so there is one single body that can coordinate all the regulations and permits. That will facilitate exploration activities in the country,” he said. He added that with most of the reserves now located in frontier and more difficult areas, companies would benefit from a higher production split and more streamlined regulatory procedure.
According to Carol Nakhle, Energy Economist at the University of Surrey, UK, fiscal regime is the most powerful tool that a government has to directly influence oil and gas production.
“Three factors drive production — price, technology and fiscal regime,” she said, adding that while price and technology are not within the government’s control, fiscal regime is.
“What investors look for in a fiscal regime is stability and clarity,” she said. “If you have a lack of clarity, you are imposing additional risks and nobody wants that,” she said.
Several high-profile projects in Indonesia have fallen prey to either a complex permit structure, bureaucracy, or unattractive and uncertain fiscal terms.
Cepu is one project to have fallen victim to permits. The PSC for Cepu was signed in 2005 and it was meant to reach full production at 165,000 b/d in early 2010, but was hit by permit issues and changes in local government regulations, and is yet to reach full production. It currently produces around 30,000 b/d.
Another ExxonMobil and Pertamina project to be suffering from delays is the giant but technically challenging East Natuna project. Pertamina CEO Karen Agustiawan during her speech at the conference urged the government to hurry up on it.
Given the complexities surrounding East Natuna’s CO2 content, the partners have asked the government to extend the PSC duration and also make the contract terms more attractive — issues on which the government has dragged its feet.
Total has meanwhile been battling with the government for an extension to the Mahakam PSC, which is set to expire in 2017, to enable it to invest more and develop the remaining resources there, but no solution seems to be in sight.
“Total has exploited 80% of the reserves, but there is still lots there,” a Total executive said.
—Mriganka Jaipuriyar in Singapore
