Indonesia's crude oil production fell to 1.01 million barrels per day in 2006 from 1.06 million barrels in the previous year, much less than the government's budget target of 1.05 million barrels per day.
Mature fields, high exploration risks, excessive regulation and inefficient production are the key problems causing the drop in crude oil production.
Refinery inefficiency exacerbates the problem, making imports a must if the economy is to grow above 6 percent this year.
A better regulatory framework could overcome some of the issues.
Will we see another decline in production? Do we have to continue importing oil to meet our economic growth targets? And what is the government doing to ramp up oil production?
First, most of the current fields, which are operated by 52 different operators under different contracts, passed their peak production in 1977, or have reached maturity.
Second, opening up new blocks is a slow process, whether due to the economic feasibility of developing some of the blocks put out to tender, or the long bureaucratic selection processes for both the blocks being tendered and for the operators. For example, out of 41 blocks being tendered, the processes in only 21 blocks have been concluded, and this took between 5 and 6 months. So far, 18 blocks have been awarded, with the remaining blocks being carried over to the next tender.
However, it will take at least another 2 years before oil production starts, if oil is discovered at all. These delays serve to increase costs. And, adding to all this is the signature bonus requirement, which contractors have to pay when they are awarded their blocks. Total signature bonuses paid to the government amounted to about US$44.5 million last year. These additional costs will hamper production growth this year. We may, however, see some production upside from a number of existing fields, about 12 in all.
The reality at the present time is higher investment costs, but lower output.
Mature fields are a major problem, being more expensive to maintain, while output remains low. If we look at the map of available reserves in Indonesia, most of the prospective fields, mainly onshore, are already being exploited, leaving the remaining blocks offshore.
The problem here is that development costs for offshore blocks are a lot higher, especially given that rental rates for drilling rigs went up threefold last year. Even where the capital resources are available, production may not start for several years, as in the case of the Natuna block.
Fortunately, most development costs are recovered under the cost-recovery system, which provides an incentive for continued exploration. But, of course, the costs can still only be recovered after the blocks commence commercial production.
While the details of the costs recovered are vague, they are definitely increasing in value.
Last year, cost recovery amounted to US$9 billion, or about US$11 per barrel, up by 20 percent from US$7.5 billion in 2005. Still, if compared with other countries, such amounts are still reasonable. But going forward, we will see increasing cost recovery in line with increased development of new blocks, and more expensive maintenance of existing fields, unless oil prices drop below the US$45 per barrel level, which would make investment in oil and gas uneconomic.
Not only is Indonesia's production declining, but the refining sector is inefficient, making imports a must. Existing refining capacity is about 1.057 million barrels per day, but only about 65 percent of total capacity was produced last year.
Modernizing the country's refineries will cost between US$1 billion and $1.5 billion, while building new refining capacity will cost between US$4 billion and $5 billion.
Given that Pertamina, which currently controls the majority of downstream activities, is exceedingly short of money, it will be some time before new refining capacity is built.
The oil and gas downstream authority (BPH Migas) expects two refineries -- Hemoco Selayar and Situbondo -- to have come onstream by 2011. Until then, we will have to rely on our existing inefficient refineries and, of course, imports.
Excessive regulation is another problem, in our view, despite the making of some changes to facilitate foreign investment. We believe there are two regulations that are in the pipeline that will likely cause problems.
First, the proposed change in the obligation imposed on oil producers to sell their production on the domestic market from a maximum of 25 percent to a minimum of 25 percent, and the requirement to supply gas to the domestic market. The latter will be changed from 58.4 percent of the total gas produced for export and 41.6 percent for the domestic market, to a ratio of 50:50.
While this will help to meet domestic demand, it certainly reduces the incentive for oil and gas companies to further explore their blocks given that the export market commands higher prices.
Low production is a problem, and to rectify this, the government is planning to provide various incentives, such as: 1) additional cost recovery of 20 percent for marginal oil fields (about 300 fields in all); 2) a better split, with the government taking a lower portion (down from 70 percent to 51 percent) if the contractor is willing to develop a gas field for the domestic market; 3) continued tendering of blocks (30 blocks this year); and 4) revision of VAT on exploration activities.
What does all this mean? There will be more investment in the sector, given that most of the current blocks are marginal and the prospect of a higher level of profitability from better splits.
Efficiency may kick in, in particular when the government decides to limit cost recovery. Production may also accelerate faster than previously anticipated. All this should translate into better returns going forward. And, if the improved regulatory framework is properly implemented, oil and gas production could, in fact, increase by 30 percent by 2009.
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