This Selected Issues paper for Indonesia reports that following the major cleanup of the banking sector after the crisis, banks’ performance has improved as net interest margins and profitability have increased. Public and external debt ratios have declined and international reserves have risen, reducing domestic and external vulnerabilities. Indonesia stands out as having experienced a slower recovery in investment and exports than other countries hit by the Asian crisis. Recognizing the challenge, the government has adopted a sound medium-term strategy focused on boosting economic growth.


This Selected Issues paper for Indonesia reports that following the major cleanup of the banking sector after the crisis, banks’ performance has improved as net interest margins and profitability have increased. Public and external debt ratios have declined and international reserves have risen, reducing domestic and external vulnerabilities. Indonesia stands out as having experienced a slower recovery in investment and exports than other countries hit by the Asian crisis. Recognizing the challenge, the government has adopted a sound medium-term strategy focused on boosting economic growth.

VI. The Oil and Gas Sector: Prospects and Policy Issues1

A. Introduction

1. Although the petroleum sector remains a major part of Indonesia’s economy, its importance has declined over time. While Indonesia ranks seventeenth and eighth among world producers of oil and of gas, respectively,2 dwindling investment, structural factors (such as aging fields), increasing costs, and high levels of fuel subsidies have over time eroded the contribution of the sector. Indeed, Indonesia’s oil production has been declining, remaining well below its OPEC quota for several years, proven reserves have halved since 1983 to less than 5 billion barrels, and Indonesia is currently a net oil importer. Gas production increased rapidly from a low base in the 1970s to the mid-1990s, but has since stagnated.

2. This chapter reviews the contributions of the oil and gas sector to the Indonesian economy and its future prospects. After an overview of recent developments and policy initiatives, the chapter discusses Indonesia’s regulatory and fiscal arrangements in an international context, the government’s energy reform strategy, and options for attracting investment.

B. Recent Developments and Policies

3. Both oil and gas production has stagnated in recent years. In 2004, Indonesia produced 1.04 million barrels of oil per day (mbd), well below the peak of 1.6 mbd reached in 1991 and also more than 20 percent below its OPEC quota. The decline in oil production has been especially rapid in recent years, with an average fall of about 6 percent annually during 2000–2004. Gas production has stagnated at or below 8 billion cubic feet per day in the last few years. As a result, the overall contribution of the petroleum sector has declined over time:

  • The sector currently accounts for around 10 percent of GDP, down from 12 percent in 1991, notwithstanding the currently high oil prices.

  • Oil and gas related export earnings totaled around US$18 billion or 25 percent of total export value in 2004, compared to over 40 percent in 1990, and around 60 percent in the early 1980s. At the same time, oil imports have been on the rise, with oil and gas imports amounting to some US$11 billion or nearly 25 percent of total imports value in 2004, compared to less than 10 percent a decade ago. In fact, Indonesia has become a net importer of oil, although it still remains a net petroleum exporter thanks to its gas exports.

  • In 2004, oil and gas revenue accounted for about 27 percent of government revenue, compared to over 40 percent in 2000.3 The sector’s net contribution to the budget has been further eroded by large fuel subsidies, to keep domestic consumer prices down, which amounted to 3 percent of GDP in 2004.


Contribution of Oil Gas to Overall GDP and International Oil Prices

Citation: IMF Staff Country Reports 2005, 327; 10.5089/9781451818352.002.A006


Oil and Gas Exports and Imports

Citation: IMF Staff Country Reports 2005, 327; 10.5089/9781451818352.002.A006

Sources: IFS Database

Oil Production vs Consumption in Thousands of Barrels per day

Citation: IMF Staff Country Reports 2005, 327; 10.5089/9781451818352.002.A006

Sources: IFS Database

4. Oil consumption has been growing rapidly while production has been declining. Oil consumption has increased at an average rate of around 5 percent since 1990 while production has been declining as discussed above. A major factor driving oil consumption in Indonesia is the low domestic price of fuel.4

5. Gas production is double the level of gas consumption, but consumption has been increasing at a faster pace than production. Since 1990, gas production growth at 3.7 percent per annum has been below consumption growth averaging some 4.2 percent; however, production levels are still double that of consumption so that gas has become increasingly important to the Indonesian economy.

6. Exploration expenditure in real terms and new field exploration drilling has fallen to 35 year lows (IPA, 2004). While development expenditure has been rising, this reflects in part rising unit costs. Moreover, overall production costs are rising as fields mature and operators face higher costs, including labor costs and local government charges.

7. The number of production sharing contracts (PSCs) and technical assistance contracts (TACs) signed have also declined. Such contracts fell from a peak of 21 in 1997, to two in 2002, following enactment of the new oil and gas law in 2001, but increased again to 17 in 2004. However, many of the more recent PSCs have been awarded to small and medium-sized companies that typically have only regional operations.


Oil and Gas Companie’s Annual Expenditure, 1997–2004

Millions of US dollars

Citation: IMF Staff Country Reports 2005, 327; 10.5089/9781451818352.002.A006

8. Although there are some common factors that have affected investment in the sector internationally, the declining trend in Indonesia is also indicative of the investment climate in the country. A recent study by IMF staff (2005) suggests that the relatively low real oil prices during the 1980s and 1990s and the volatility and unpredictability of these prices, combined with the substantial upfront outlays, the irreversibility of investment, and uncertainty about future cash flows, constrained global exploration activity. While these factors could partly explain the low investment in the Indonesian oil and gas sector, country-specific factors, including weaknesses in the broader investment climate—such as contractual, legal, and policy certainty, labor market rigidities, and infrastructure weaknesses—have also been important.5 Specific factors which may have dampened investment in Indonesia include:

  • Slow implementation of the new oil and gas law passed in 2001: The new law changed the regulatory structure in the oil and gas sector with the creation of two new agencies, BPMigas and BPH Migas, now responsible for upstream and downstream regulations, respectively, and transformation of state-owned petroleum company Pertamina (previously responsible for production and regulation) into a limited liability company (Box VI.1). The associated implementing regulations were delayed, creating regulatory uncertainty in the sector, although all but one have now been completed.

  • Amendments to the law required by the Constitutional Court are still pending: These amendments relate to the domestic market obligation of oil and gas companies (so that they may now be required to sell at least 25 percent as opposed to up to25 percent) in the domestic market; and to the setting of oil and gas prices.

  • Proliferation of regulations: In the wake of decentralization, oil and gas companies often face increasing and conflicting regulations adopted by regional governments, which may be different from those agreed in the companies’ contracts with BPMigas.

  • Negative sentiment and forgone production related to high-profile protracted negotiations: ExxonMobil and Pertamina have been in protracted negotiations over the Cepu oilfield (relating to an extension of Exxon Mobil’s contract) where ExxonMobil recently discovered large reserves. The latest reports suggest that an agreement has now been reached.

  • Regulatory uncertainty regarding taxes and import duties: Some PSCs include VAT exemptions, but such exemptions (and contracts) have in some cases been reviewed by the government and the exemptions withdrawn. More recently, the government has announced VAT exemptions on capital imports by oil and gas companies.

  • Delays in VAT refunds and other tax disputes: While VAT used to be refunded by Pertamina to PSC companies, the refunding is now the responsibility of the upstream regulator, and there are reports of long delays in refunds.

C. Indonesia’s Fiscal Regime—An International Perspective

9. Many oil-producing countries rely on foreign participation as a means to attract investment and know-how. Given the large-scale outlays required for exploration, oil companies typically require government incentives. While the overall framework for oil exploration and production is generally through production-sharing agreements and, to a lesser degree, joint ventures, the terms of the production-sharing agreements vary not only from country to country but also within countries depending inter alia on the location of the oil wells. For example, off-shore oil exploration usually requires more generous terms on PSCs to recover the cost than on-shore exploration. Country risk also plays an important role as a motivation for government incentives. Finally, the fiscal regime—in terms of both corporate taxes and tax exemptions—is an important determinant in an oil company’s choice of countries.

10. Indonesia’s PSCs have become more generous over time. Under the early PSCs, contractors received 15 percent and the government received 85 percent of the total oil revenues after production costs were deducted. More recently, the PSC terms have become more generous. In 2003, in 11 of the 15 PSCs signed, the share of the contractors increased to a range of 20–25 percent (with most receiving 25 percent) for oil, and 35–45 percent for gas (with an average of 40 percent). In 2004, 10 of the 15 PSC contracts awarded provided shares to contractors in the range of 20–35 percent for oil, and 35–40 percent for gas.

11. As regards the fiscal and regulatory regime, Indonesia’s income tax rates are comparable to those in the region (Table 1). Indonesia’s income tax rate on the oil and gas sector is similar to that of the countries in Asia but Indonesia has no resource rent costs (RRCs). On the other hand, Indonesia’s PSC terms give the government one of the highest shares in oil revenues in the region. RRCs generally apply only when a company is making excess profits, and become binding only when oil prices are very high. In contrast, favorable terms on PSCs have an immediate effect on cash flow once sales begin. In that respect, generous terms on PSCs are preferred by companies. Under the current outlook for oil prices, the absence of RRCs may partly offset the less generous terms on PSCs. Nevertheless, investors have also sought better terms on PSCs to cover the costs, especially for aging fields, and also for political and regulatory uncertainty as they seek to maximize risk-adjusted returns.

D. Economic Policies to Attract Investment

12. Future production levels will depend on new fields coming on stream, structural factors, and future investment. The near term profile of oil and gas production would depend on important new finds such as Cepu.6 Even with new production coming on stream as currently expected, the bulk of production would come from mature fields in which output is declining. Also, new exploration is increasingly in more difficult or “frontier” regions, entailing higher exploration costs. Future oil and gas demand will depend, among other things, on Indonesia’s petroleum pricing policy and broader energy strategy, as well as international price developments and overall economic growth. Box VI.2 presents technical scenarios that illustrate the long-term implications of different outcomes in the petroleum sector.

13. With this is mind, the new government has been working to attract foreign investment in the petroleum sector and at the same time has devised a new energy policy. Important developments in this regard are:

  • A renewed push to complete the new regulatory framework and clarify issues relating to tax and duties under existing PSCs. The new framework constitutes major improvements in the environment for investment in the upstream oil and gas sector. Further progress to reduce the regulatory uncertainty would be achieved through completion of the pending amendments to Law 22/2001 (as required by the Constitutional Court), and the clarification of conflicting and overlapping regulations, such as those between central and local governments.

  • Improvements in fiscal incentives, such as the enhancement of PSC terms for contractors, and incentives to boost production in marginal oil fields.7

  • Conclusion of outstanding disputes and contract discussions, including the Cepu field contract negotiations. A conclusion of these discussions would also be beneficial to the overall investment climate. A resolution of long outstanding issues relating to tax refunds and rebates would also contribute in this regard.

  • Increasing significantly the number of blocks offered. In this regard, 27 blocks are planned to be offered in June 2005, of a total of 70 blocks planned for to be offered during 2005–2006.

  • A new energy policy aimed at better managing and utilizing energy resources. The recently launched Blueprint for National Energy Development, 2005–20, outlines an integrated energy management strategy. On the supply side, the strategy aims to augment energy production whilst diversifying fuel sources in power generation, and on the consumption side it aims to improve efficiency of energy use. The strategy recognizes the need to move energy consumer prices to “economically viable” levels and targets this to be completed by 2010. Other key objectives of this strategy are, by 2020, to: (i) reduce the role of crude oil in power generation from around 50–55 percent to 10–15 percent (through increasing the use of coal, gas and geothermal power); (ii) reduce the intensity of energy use by 1 percent a year; (iii) improve energy infrastructure, such as oil and gas pipelines; and (iv) create a secure supply of energy.

E. Conclusions

14. While Indonesia’s oil and gas sector will play a diminishing role in the economy going forward, it will remain a key sector, and the renewed policy efforts are important in augmenting investment and production. The government is aiming to boost investment and production, while on the demand side, reduce reliance on oil and move toward more efficient utilization of oil and gas resources, including through pricing policies. The major regulatory changes introduced since 2001 have been an important step in this regard. The key implementing regulations are largely complete, and some of the outstanding issues relating to VAT and import duty obligations have been settled recently. Assuming the amendments required by the Constitutional Court are completed quickly and flexibly, and given the various (fiscal and other) initiatives being offered by the government, developments in regard to investment and production may turn around. Nevertheless, in the longer run, Indonesia needs to prepare for major structural changes as the contribution of the oil and gas sector to GDP, foreign exchange earnings and government revenues inevitably will decline over time.

Regulatory Developments in the Oil and Gas Sector

Previous Regulatory Structure

Prior to 2001, Pertamina acted both as the state oil and gas company and as the industry regulator—a situation which created conflicts of interest and related problems for investment, governance and transparency in the sector. Law No. 8–1971, established Pertamina as both operator and regulator with duties ranging from the tendering of blocks, managing data, awarding production sharing contracts (PSCs), to operating the downstream sector. Pertamina operated all domestic refineries and was responsible for ensuring the domestic supply of refined oil products. In addition, Pertamina was the sole buyer of all natural gas produced domestically and had the sole responsibility for negotiating contracts for the export of LNG. This system limited competition in the downstream sector and introduced a number of distortions. The monopoly and public obligation assigned to Pertamina, along with the petroleum subsidies, led to underinvestment in the downstream sector. Indonesia’s diminishing levels of oil production and reserves underscored the need for a more effective regulatory regime.

New Regulatory Structure

Indonesia passed a new oil and gas law on November 23, 2001 that introduced major changes in the regulatory structure as part of the deregulation and reform effort in the energy sector. Law No. 22–2001 provided for a clear separation between upstream and downstream activities. It transferred regulatory authority from Pertamina to the Directorate General of Oil and Gas (DG MIGAS) in the Ministry of Energy and Mineral Resources, and to two new regulatory agencies: Badan Pelaksana Minyak dan Gas Bumi (the “Implementing Body for Oil and Gas” or BP MIGAS) for the upstream sector, and Badan Pengatur Hilir Minyak dan Gas Bumi (“the Regulatory Body for Downstream Oil and Gas” or BPH MIGAS). Government Regulation 31 of 2003, established Pertamina as a state owned limited liability company. Under the new law, the tendering of blocks for exploration come under the authority of DG MIGAS, which is responsible for gathering premilinary data on blocks, conducting the auctions, awarding contatcts, and issuing the contracts. The final contracts, however, are signed by the newly created upstream regulatory authority. BP MIGAS was established by Government Regulation 42, issued July 16, 2002. BPH MIGAS, which was established on December 30, 2002, was created by Regulation 67 of 2002 and Presidential Decree number 86 of 2002. As the regulatory agency for the downstream oil and gas sector, its responsibilities include domestic fuel distribution, national oil fuel reserves, tariffs for natural gas pipelines, and gas prices for households and small customers. Law No. 22–2001 also established the liberalization of the downstream sector. Pertamina is set to lose its monopoly and its public service obligation (its responsibility to ensure the national fuel supply) at the end of 2005. New entrants and licenses for the downstream sector will be issued by BPH MIGAS.

These new laws and regulations largely complete the regulatory framework for the oil and gas sector, although amendments following the Constitutional Court review of the law are pending. Many of the important subsidiary regulations under Law No. 22–2001 have now been issued including those establishing Pertamina as a private company, establishing BP MIGAS and BPH MIGAS, and more recently (October 2004) two separate implementing regulations, for BP MIGAS and BPH MIGAS relating to the operational aspects of these agencies. Industry representatives report some remaining conflicts or ambiguities among various statutes and some unintended consequences which may continue to act as disincentives to investors. Finally, the Constitutional Court’s recent review of Law 22/2001 (in the context of Article 33 of Indonesia’s Constitution), required amendments relating to the domestic market obligation of gas producers, and to the pricing of gas and fuel oil (which was market determined under Law 22/2001). Thus, there remains some work to complete the regulatory framework and remove uncertainty and disincentives for investment.

Contribution of the Oil and Gas Sector: Alternative Scenarios

The scenarios below are based on three simple assumptions—production increasing by 3 percent a year, remaining constant, and declining by 3 percent a year. Under Scenario 1, where the government successfully tackles the impediments to investment, production increases by 3 percent a year (ignoring the long gestation between investment and actual production), although oil consumption still exceeds production. In this scenario, positive net gas exports would persist throughout the period. In Scenario 2, where more modest reforms and investment result in the maintenance of the current level of oil and gas production, the imbalance between oil demand and supply quickly increases and net oil imports increase. Meanwhile, gas demand would continue to exceed supply for some time. In Scenario 3, where production is expected to decline by 3 percent a year, a large imbalance emerges early on, such that Indonesia becomes a net importer of oil and gas and the contribution of the sector to GDP, exports and government revenue declines rapidly.

Even under the most optimistic scenario, the relative contribution of the oil and gas sector to the Indonesian economy would decline markedly within a decade. If oil and gas production grew by 3 percent a year, by 2015, its share of GDP would halve and its contribution to government revenue would fall below 17 percent. In the pessimistic case in which production declines by 3 percent per year, within a decade the sector would account for less than 3 percent of GDP, and around 10 percent of total exports and government revenue. Indeed, depending on the rate of growth of consumption and imports, net oil and gas exports would decline rapidly and Indonesia could become an overall importer of oil and gas within the next decade. While these scenarios are mechanical, they illustrate the importance of increased investment and production in the oil and gas sector


Gas Productions and Consumption Scenarios

In Million of tonnes equivalent

Citation: IMF Staff Country Reports 2005, 327; 10.5089/9781451818352.002.A006


Gas Productions and Consumption Scenarios

In Million of barrels

Citation: IMF Staff Country Reports 2005, 327; 10.5089/9781451818352.002.A006

Indonesia: Long-Term Implications of Oil and Gas Sector Growth/Stagnation/Decline for the Composition of GDP, Exports, and Government Rev enue

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Table 1.

Comparison of Fiscal Terms for Selected Oil and Gas Producing Countries

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Source: Fiscal Policy Formulation and Implementation in Oil-Producing Countries (2003), edited by Davis; and IPA.

Government share of revenue.


  • Hausmann, Ricardo and Roberto Rigobon, (2003), “An Alternative Interpretation of the “Resource Curse”: Theory and Policy Implications”, Fiscal Policy Formulation and Implementation in Oil-Producing Countries, International Monetary Fund, Chapter 2, p.13.

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  • McPherson, Charles, (2003), “National Oil Companies: Evolution, Issues, Outlook”, Fiscal Policy Formulation and Implementation in Oil-Producing Countries, International Monetary Fund, Chapter 7, p. 184

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  • “Presidents Report for CY (2004),” Indonesian Petroleum Association (IPA).

  • International Monetary Fund (2005), “World Economic Outlook,” April.

  • International Monetary Fund (2005), “Oil Market Developments and Issues(


Prepared by Nita Thacker and Yougesh Khatri (both APD). The chapter draws on research done by Daniel Chirpich during a 2004 summer internship at the IMF’s Jakarta office.


Indonesia’s proven oil and gas reserves account for a relatively small share of the world’s total reserves (0.4 percent and 1.5 percent, respectively), while oil and gas production represent 1.5 percent and 2.8 percent of world production, respectively.


As a result of decentralization, a large share of oil revenues are now transferred to local governments.


In 2004, pump prices for gasoline in Indonesia were US$0.27 per liter, compared to US$0.89 in Singapore, US$0.87 in India, and US$1.54 Hong Kong SAR (GTZ survey, 2004). Even after the March 2005 fuel price hikes (averaging 29 percent across products), pump prices remain among the lowest in the world, reflecting still high levels of subsidization of fuel consumption by the government.


Chapter V of IMF Country Report No. 04/189 provides a fuller description


Major new production potential include: the Cepu field which could boost oil production by up to 15 percent of current oil production not to mention its substantial gas reserves and the Tangguh project (comprising on-shore and off-shore blocs in Irian Jaya) which is reported to have around 14 TCF of gas and initial production capacity of 7 million tons/year.


Under a recently issued ministerial regulation (08/2005), contractors can claim a refund of 20 percent of operating costs incurred in the establishment of a viable producing marginal oil field, subject to annual review and a cumulative rate of return ceiling of 30 percent, at which point the incentive would cease.

Indonesia: Selected Issues
Author: International Monetary Fund