Once a key pillar of the Indonesian economy, the energy sector has declined in influence as oil and gas production continues to fall from peak levels. The hydrocarbons sector, which is valued at an estimated $20bn, contributed 3% to state revenues in 2016, down from 14% in 2014 and 25% in 2006. Yet the value of Indonesia’s energy sector cannot be reduced to its direct contribution to national GDP, as the power and oil and gas sectors remain a critical component of the infrastructure necessary to sustain economic growth across every other industry.

With this in mind, the government has made significant changes to the regulatory structure of the power and hydrocarbons sectors in a bid to boost electricity capacity and electrification ratios while expanding domestic oil and gas production and reducing fuel imports. In the power segment, these new regulations are being put in place largely to stimulate private investment in electricity generation while lowering production costs as part of the plan to add an additional 35 GW of capacity by 2019. The aim is also to increase the share of renewables in the energy mix to more than 20% by 2026. Meanwhile, the government hopes to stem the tide of declining oil and gas production by tapping into new domestic reserves to keep pace with rising consumption.

DECLINING CRUDE: In its heyday, Indonesia’s oil and gas sector was among the most productive in the world outside the Middle East. At its peak in 1977, the country produced more than 1.6m barrels of oil per day – well above the amounts required for domestic consumption. This output provided a steady stream of revenue that the government relied on to fuel industrial manufacturing and to drive wider economic development.

Indeed, industry earnings helped to transform Indonesia into an emerging regional power, driving economic growth and diversification. Fast forward to today, this same resource is in danger of stalling. The maturity and decline of existing hydrocarbons fields, along with a less attractive regulatory environment (see analysis), has led directly to progressively lower investment and productivity in the sector over the past decade. Since 1995, oil production has declined steadily from more than 1.6m barrels per day (bpd) to approximately 800,000 bpd in 2014.

TRADE IMBALANCE: In the past three years, crude output has stabilised with annual production of 789,000 bpd, 786,000 bpd and 831,000 bpd in 2014, 2015 and 2016, respectively, according to PwC’s “Oil and Gas in Indonesia – Investment and Taxation Guide” published in May 2017. At the same time, ongoing economic growth continues to fuel energy demand which is creating larger energy trade imbalances with each passing year. In 2016 the country consumed more than 1.6m bpd, up from less than 1.2m bpd in 2000.

Indonesia has not produced more crude oil than it consumes since 2002. In spite of this sluggish output over the past two decades, as of 2016 the country still held an estimated 3.31bn barrels of proven oil reserves and 3.94bn barrels of potential oil reserves, according to PwC’s report quoting data from the Directorate General of Oil and Gas, which is part of the Ministry of Energy and Mineral Resources (MEMR).

REGULATORY ENVIRONMENT: New laws and regulations governing the oil and gas sector are introduced frequently. Amendments have been made to boost the attractiveness of terms for potential developers or to increase the government’s share of contracts. However, implementation is not always without challenges. One of the more significant regulatory additions was Government Regulation No. 79 of 2010 (GR 79/2010), which led to years of uncertainty as supporting legislation was discussed and implemented at an uneven pace. Regulators introduced Government Regulation No. 27 of 2017 (GR 27/2017), which addressed many of the negatively received aspects of GR 79/2010, including the land and building tax on offshore operations. These efforts were recently enhanced with a tweaking of the tender process from a net split to a gross split which marks a shift away from the original form of the production-sharing contract (PSC) (see analysis).

The previous sector regulator, BP Migas, operated under the title of “special entity”, which was defined as neither a state-owned organisation or government body. The government reconfigured the entity into SKK Migas in 2013, although its role and regulatory function remain complex. Additionally, state-owned oil and gas company Pertamina is faced with the challenge of trying to satisfy both its responsibilities to the state as well as its partnership role in working with international oil companies (IOCs).

NATURAL GAS: Indonesia’s hydrocarbons sector switched from an oil-dominated industry to one led by gas in 2004 as it became a net importer of oil and declining crude production gave way to new, highly productive natural gas fields. As of 2016 the country controlled the 10th-largest proven natural gas reserves in the world at 102trn cu feet.

Yet in recent years, declining production has led to the development of a domestically oriented energy strategy intended to provide more fuel to the local market for electricity production and industrial use. This trend, along with output from major new liquefied natural gas (LNG) projects in Australia and Qatar, has led to Indonesia’s international market share declining from 2.6% in 2010 to 2% by 2016.

The majority of gas production, which peaked at 8.86bn standard cu feet per day (scfd) in 2010, is centred around the three regions of East Kalimantan, South Sumatra and Natuna. Production dropped off to 6.8bn scfd in 2013 before recovering slightly to achieve 8.1bn scfd in 2015 and 7.9bn scfd in 2016.

Much of this production is currently controlled by large IOCs, although Pertamina is taking an increasing interest in production shares. France’s Total E&P Indonesie and London-headquartered BP remain the most prolific producers of gas in the country, with each accounting for 22% of gas produced in 2016, according to PwC. Total’s output is derived from the Mahakam Block, while BP controls the Tangguh project, which is also set for expansion (see analysis). Other major players active in the sector include ConocoPhillips, which produced 17% of national output from its Corridor PSC; Pertamina, which accounted for 12% of gas from a variety of projects; and a number of other smaller companies including Medco E&P, Premier Oil, Kangean Energy, VICO and others.

In terms of domestic distribution, the current system is adequate for point-to-point transfer, but remains inflexible in its use and range. A new network of trunk lines and LNG terminals would improve access to supplies, whilst creating competition and boosting the volume of gas available. To this end, network development plans have been rolled out by Pertamina and its gas subsidiary Pertagas, although simply combining the two plans into a single national plan could prove tricky given the different priorities and developmental targets contained within the strategies.

NEW PRODUCTION: The Jangkrik fields, discovered in the Muara Bakau block at a depth of 400 metres in the Makassar Strait off the east coast of Kalimantan, is the first of a handful of strategically important upstream projects to begin gas shipments in May 2017. Italian multinational oil and gas producer Eni is heading up the gas project with a 55% stake. Eni acts as an operator with other joint-venture (JV) partners GDF Suez Exploration Indonesia, a subsidiary of ENGIE, formerly GDF SUEZ, with 33.33% stake; and Saka Energi Muara Bakau with an 11.67% stake. The deepwater field yielded its first gas in May 2017 with the first shipment coming a month later. The project is made up of two primary gas fields of Jangkrik and Jangkrik East in the hydrocarbons-rich Kutei basin. Its 10 subsea wells, which are linked to the new floating production unit (FPU) Jangkrik, will continue to ramp up production through the end of 2017, with peak production expected to reach 450m scfd, or 83,000 barrels of oil equivalent per day (boepd). The FPU Jangkrik is connected to an onshore receiving facility in Kalimantan via a 79-km pipeline, which is linked to the East Kalimantan transport system and the Bontang gas liquefaction plant. Gas output from Jangkrik is being split between Eni for sale as LNG on the international market and to Pertamina for the domestic market under a long-term contract. The first LNG cargo, totalling 22,500 cu metres, was shipped from Bontang to Bali in June 2017.

The Jangkrik FPU may also be used as a development hub for Eni’s Merakes gas discovery, which is located approximately 35 km from the Jangkrik field. The Merakes prospect lies within the East Sepinggan PSC. Eni holds an 85% participating interest and acts as operator, with Pertamina Hulu Energy holding the remaining 15%. The appraisal well, Merakes-2, was successfully completed in January 2017 in 1.27 km of water. It confirmed the extension of an earlier discovery made in 2014 through the Merakes-1 well. Estimated to contain at least 2trn cu feet, with further potential yet to be evaluated, the Merakes discovery will utilise existing infrastructure at the nearby Jangkrik field.

PLANNING AHEAD: After several years of depressed commodity prices, small and medium-sized oil and gas companies have cut back exploration and production (E&P) activity, and even the major IOCs have become more selective in their investment choices. While this worldwide trend has had a negative effect on Indonesia’s E&P activity, it does not fully explain the extent of the fall in investment inflows. In 2016 investment in the upstream oil and gas sector totalled $11bn, or 78% of the target set in the 2016 Revised Work Programme and Budget of SKK Migas, representing a 25% fall from the $14.8bn invested in 2015. The majority of investments in 2016 were channelled into existing production, which accounted for 74% of the total. Another 12% went towards well development, 8% to administration and 6% to exploration activities, according to the regulator’s annual report 2016.

Investments in upstream oil and gas exploration in 2016 represented 11% of the total spent on exploration in 2011, dropping from $2.12bn down to $237m in six years. A significant reason for this is that most of the focus on exploration is now centred on eastern Indonesia in deepwater areas which are technically challenging and expensive to exploit. This, when combined with oil prices hovering around $60 per barrel and a lack of continuity and incentives in the regulatory environment, have left many IOCs reluctant to invest.

Evidence of how the operating environment has affected the sector can be found in the slow progress made on US company Chevron’s Indonesian Deep-water Development (IDD) project, which was initially approved by the government in 2008. A technically challenging but potentially highly productive field, government indecision and regulatory changes have repeatedly delayed the project. Today, even though the partners were able to announce the successful delivery of the first gas from the initial Bangat field in 2016 (see analysis), further development of the second and third stages of the project remains uncertain. Although phase one will provide a much-needed new source of gas, output will remain below original project plans without the addition of the second and third fields. This could prove particularly detrimental to the government as the state could lose out on most of its revenue share due to cost recovery compensation owed to the developer Chevron, which bore the up-front developmental costs and risk. This could account for the majority of the government’s share of revenues as the developmental costs are being offset by only one producing field rather than being spread over the entire project as originally planned.

NEW CONTRACT ROUND: Another tactic which the government is employing to boost upstream activity is offering up new blocks for bidding. The most recent bidding round ran from May to September 2017 and consisted of 10 conventional blocks and five non-conventional blocks under the new gross-split PSC scheme. The failure to attract any bidders in this round of tenders was attributed to a prolonged delay in the issuance of taxation regulations for the new gross-split scheme. Local media reports in October 2017 indicated that the government planned to issue a further round of tenders before the end of the year.

This follows the offering of 17 blocks in 2016, which generated lacklustre interest from potential developers and ultimately resulted in only one of the blocks being acquired. Besides the slump in global commodity prices, there were three main reasons for this lack of interest. First, the new gross-split formula, which was intended to assuage private sector concerns, actually raised new doubts among investors (see analysis).

“Companies were not interested because the formulation of the gross-split was not clear and it did not take into account cost recovery,” Anton Wahjosoedibjo, member of the energy executive team in the Mines and Energy Society and president-director of energy consulting firm PEN Consulting, told OBG. “With no cost recovery, the risk is born entirely by the developers, who must then reduce costs if they want to maximise revenues.” Second, the majority of areas offered were relatively small and were generally characterised by complicated, high-risk geography, according to Wahjosoedibjo. Final issue with the tenders was the government’s reliance on older seismic data which is not as reliable as data and analysis derived from more modern remote-sensing methods.

EXPIRATION DATE: In addition to the challenges surrounding the upstream IDD project and lack of interest in new blocks, the fate of active but maturing oil and gas fields is an increasingly pressing concern as numerous high-profile PSCs are set to expire in the coming years. Because the authorities recently reworked the PSC system governing oil and gas deals and have yet to make a decision on the renewal of existing contracts – either under the original system or the new one – current operators of these fields have been reticent to make further investments to maintain output levels (see analysis).

“The biggest issue facing the government is the fact that many large producing blocks are coming to the end of their contract terms in the coming years,” Sacha Winzenried, lead advisor for energy, utilities and mining at PwC Indonesia, told OBG.

There are indications that Pertamina could take over certain expiring contracts, although some of the maturing fields would also require specialised expertise to maintain. France’s Total and Japan’s Inpex, as well as US firms Chevron and ExxonMobil, all have blocks expiring by 2022, making them prime targets for Pertamina should their contracts not be renewed.

“Assets such as Offshore Mahakam, Corridor and Jabung would be of interest to Pertamina as these are material gas-exporting projects with exposure to LNG and piped gas contracts,” Alex Siow, upstream research analyst, noted in a Wood Mackenzie report in November 2016. Corridor and Jabung, for example, provide gas to the Singapore and West Java markets, while Offshore Mahakam is able to offer LNG through the fully depreciated Bontang liquefaction plant.

However, given financial and technical constraints, it is likely that Pertamina would want to work in cooperation with companies that have existing capabilities for such project management. “Taking up minority interest in more technically challenging projects will also allow it to develop the skills needed on its own assets as they near end-of-life,” the report continued.

NEXT STEPS: Wood Mackenzie valued Indonesia’s 35 expiring oil and gas PSCs at close to $10bn with the combined output of the blocks totalling more than 1m boepd in 2016, representing a sizeable chunk of domestic production. The expiring PSCs fall into a variety of categories including: mature projects with upside, enhanced oil recovery (EOR), late-life fields and discovered resource opportunities.

These expiring contracts include the most historically productive blocks in the country, such as Mahakam (currently operated by Total), Corridor ( operated by ConocoPhillips) and Jabung (PetroChina). These mature projects have already received substantial infrastructure investments, and would require relatively small ongoing investments to reap profits.

In contrast, the Rokan block held by Chevron under a PSC which expires in 2021, is more complicated to sustain. Substantial potential remains in the block, which currently supplies around 250,000 bpd. However, expensive EOR methods will be required to access these reserves. Without a guarantee of an extension, it is unlikely Chevron will undertake these investments estimated at $2.7bn in the four years leading up to expiration, although the company was engaged with the government in talks over the matter.

As of mid-2017 the government had indicated that it would only offer an extension under the gross-split scheme, which was introduced in January 2017, and Chevron had yet to announce a public decision.

In addition to these contracts, late-life assets such as Sanga Sanga, South-East Sumatra and East Kalimantan, which all operate under PSCs set to expire in 2018, could remain viable if operated efficiently, although decommissioning considerations could also drive down their attractiveness.

ELECTRIFICATION: In line with the country’s 2016-25 Electricity Supply Business Plan (RUPTL), which was issued by the MEMR in June 2016, Indonesia seeks to more than double its installed power capacity over the next decade and increase the electrification rate to 99.7% by 2025. To achieve these targets, both the government and private developers will need to overcome hurdles which have restricted growth and delayed the construction of new power plants in previous development plans. Some of the primary challenges facing the power sector include the highly dispersed population, declining production of natural gas coupled with a limited gas distribution system and a regulatory system which remains in flux.

In 2016 the country’s electrification ratio stood at 89.1%, up from 86.2% the previous year and 73.4% in 2012, according to statistics from Perusahaan Listrik Negara (PLN), the state-owned power producer and operator of the country’s transmission system. Indonesia has one of the lowest per-capita electricity consumption rates in the region. Electricity use in 2014 reached 812 KWh per capita, lower than neighbouring Vietnam (1439 KWh) and Thailand (2540 KWh), according to the World Bank.

Due to the amount of capital-intensive infrastructure required to boost electrification rates, the government and, by extension, state-owned PLN, must make difficult choices on power tariffs. As a result, development plans still largely favour coal-fired power generation, which is relatively inexpensive, although renewable energy contributions are expected to increase over the next decade (see analysis).

The government has also been working to develop the sector by issuing new regulations and amendments to existing rules. While intended to attract investment, this has also created a less stable regulatory environment than most power producers desire. The sometimes conflicting nature of the policy and regulatory changes can be attributed to the need to create the electricity infrastructure necessary to drive a modern economy forward while also providing electricity at affordable prices for less affluent citizens.

In Indonesia, where the electricity sector operates under a relatively heavily regulated system including government-set pricing, even small regulatory changes can have a significant effect on the market. As such, the constant changes have an unsettling effect on the investment environment as private companies, which as a rule seek out stability and certainty, wait to see where the dust settles.

“Indonesia’s competitiveness in terms of power generation is lagging behind certain other countries in the region,” Daniel Hwang, director of Meyz Consulting, told OBG. “Land acquiswition and bureaucracy are still some of the main constraints,” he continued.

SUPPLY & DEMAND: In 2016 the country had an installed capacity of 55.67 GW, up from 50.86 GW the previous year, according to data from PLN. In spite of ongoing efforts to liberalise the sector, PLN remains by far the largest operator of power plants in the country in addition to being the sole off-taker, transmission system operator and distributor. Of the more than 50 GW of installed capacity operating in 2016, PLN owned 39.8 GW and rented another 3.6 GW, while independent power producers (IPPs) operated a combined 11.37 GW of installed capacity.

Installed capacity is straining to keep up with ever-increasing demand as electrification rates creep upwards and industries require more and more power for expansion. In 2016 electricity production reached 248,611 GWh, up 6% compared to 2015 when output was 233,982 GWh, according to PLN data. PLN power plants accounted for the lion’s share of this output, producing 166,457 GWh of electricity or 67% to total production in 2016. IPPs leased by PLN contributed another 17,352 GWh, or 7% of total production, leaving PLN to purchase the remaining 64,802 GWh, or 26%, from private electricity producers.

Indonesia’s plentiful reserves of coal factor heavily into the power production mix, with coal-fired power plants accounting for an estimated 56% of total electricity expected to be produced in 2017. Natural gas accounts for another 26% of production, while high-speed diesel generators contribute a further 3.7% and marine fuel oil 2.9%. Hydropower plants were the largest renewable contributors with 6.4% of power produced, followed by geothermal with 4.6% and other renewable sources with less than 0.1% in 2017.

Looking forward, demand for electricity is expected to rise across Indonesia as economic growth drives up energy usage in a country of more than 260m. Power consumption is expected to expand by an average annual rate of 8.3% through to 2026, according to RUPTL 2017-26. Total production is forecast to more than double over the next decade from 233.8 TWh in 2017 to 480.2 TWh by 2026. Business and industrial users are projected to be the primary drivers of this expansion, with annual consumption rates increasing at 9.5% and 9.2%, respectively. Household and public power usage, meanwhile, is forecast to grow by rates of 7.1% and 7.5%, respectively.

The administration of President Joko Widodo has made a push to phase out electricity subsidies, which amount to billions of dollars annually. In 2017 electricity tariffs have been raised several times.

“The government’s subsidies to electricity and LPG are too high,” Lina Moeis, executive director of Rumah Energi, told OBG. “A lot of money could be saved investing in energy solutions such as domestic biogas.”

Still, it is uncertain when and if Indonesia’s power demand will outpace new supply to the extent that it would lead to an overburdened grid and frequent blackouts. Some of this ambiguity stems from con-ventional power-demand prediction tools, which are generally calculated with a GDP-growth-to-electricity-demand-growth elasticity of 1.2.

Therefore, if GDP expansion comes in at lower-than-expected rates, the consumption of electricity stands to fall disproportionally.

CAPACITY BUILDING: To meet increased demand, successive governments have rolled out power development plans over the past decade to mixed results. The first fast-track programme (FTP I) and the second one (FTP II) were rolled out in 2006 and 2010, respectively. Each programme planned to develop 10 GW of generating capacity, with FTP I composed entirely of coal-fired power plants and FTP II geared more towards IPPs and renewable energy. Progress was hampered by a number of technical, regulatory and bureaucratic obstacles, and more than 10 years after the inception of FTP I, various unfinished projects in the two programmes were rolled into a new initiative under President Widodo’s administration.

Launched in 2015, the electricity master plan 2016-21, known simply as the 35-GW plan in reference to its stated capacity boosting goals (although the initial tally of planned power projects ends up slightly higher at 36.5 GW), learned from the mistakes of the earlier fast-track programmes, with the government introducing a new regulation in 2016 to help accelerate power development and address various issues affecting the sector. The new provisions include a government guarantee for the development of power projects, which covers both projects developed by PLN, and those undertaken by PLN or its subsidiaries, in cooperation with IPPs. The regulation also covers licensing, land acquisition and various other issues.

POWER SOURCES: This plan places a much stronger emphasis on the economic costs associated with developing new generation capacity, mindful to reduce the burden of power tariffs which are regulated by PLN and subsidised from the state budget. As a result, inexpensive and domestically plentiful coal features prominently in the master plan, as does natural gas to a lesser extent. A total of 20.3 GW of new coal capacity was included in the original 35-GW plan, accounting for 56% of the total, with natural gas capacity expected to increase by 13.6 GW (37%) by 2019.

Coal mine-mouth power plants remain integral to the plan, given that Indonesia’s large low-rank coal deposits are often located in remote areas with minimal infrastructure, making transportation of the coal to population centres costly.

Sumatra in particular has substantial potential for mine-mouth coal projects given its large reserves, although the future of many of these projects remains uncertain following the cancellation of the proposed Java-Sumatra undersea cable which would have allowed the transportation of electricity from Sumatra to Java, where demand is high.

The natural gas segment will also favour power plants that are already connected to existing gas fields, or those under development, via a pipeline, preferring to use LNG-dependent facilities primarily as back-up power due to their higher cost of production.

“The proposed scheme to construct power plants at the mouth of gas fields has the potential to accelerate the 35-GW power generation plan through development of Indonesian resources,” Roberto Lorato, director and CEO of Medco Energi, told OBG.

RENEWABLES: Renewable power sources play a much smaller role, led by hydropower with 2.3 GW of new generation planned, along with 100 MW of geothermal power and 200 MW from other sources. This relatively small contribution of renewable power and continued reliance on coal in the short term has ruffled some feathers among the population and especially NGOs. Demonstrations have taken place against construction of coal-powered plants, delaying construction of one major project in Batang for several years as farmers refused to give up their land.

“The plan to rely on coal for more than 50% of the new generation should be accompanied by a financial plan explaining the benefits to the people,” Heru Dewanto, president-director of Cirebon Power Energi Prasarana, told OBG. “Indonesia is not the US or an OECD country; we need to find a balance between development costs and sustainability as there are millions of people in this country without access to electricity,” he continued.

PROGRESS: At the end of 2016 implementation of the programme was behind schedule with 2% (706.5 MW) of planned projects operational. Projects representing a further 5824 MW, or 16% of the target, were in the planning stage; while those representing 10,410 MW (29%) were in the procurement process; 8664 MW (24%) in the pre-construction phase; and the remaining 10,090 MW (28%) under construction.

The RUPTL brought some changes to the goals introduced by the 35-GW programme launched in 2015. While the initial 35-GW programme actually targeted 36.5 GW of power generation, the new total has been reduced to 35.6 GW. Targets for coal and gas-fired generation have been reduced by approximately 400 MW and 700 MW, respectively, while renewables have been boosted by 300 MW.

OUTLOOK: Indonesia’s oil and gas sector sits at a crossroads, and its future depends largely on whether oil and gas producers are willing to invest in new prospects in technically challenging areas without cost-recovery guarantees under the gross-split system.

In the shorter term, the government will need to find a solution to keep oil and gas flowing from maturing fields under expiring contracts or risk further cuts to domestic production. Pertamina is likely to take on some of these expiring contracts, although it lacks the capacity to accommodate them all and will need to continue share operational responsibility with experienced IOCs, particularly in some of the more technically challenging blocks.

Following the unsuccessful tendering of 15 conventional and non-conventional blocks by the government from May to September 2017, much will depend on whether the government can ease concerns from the private sector about the new gross-split PSC scheme. Doing so will help ensure Indonesia can be successful in reversing the decline in upstream exploration activity.

In power generation, the pace of construction of new plants will largely be tied to how well new power regulations put in place at the beginning of 2017 are received by independent producers, which account for a much larger share of new capacity than in years past. In terms of pricing, the addition of new independent power sources can also be beneficial to consumers, in that new producers will provide greater competition and could theoretically bring lower production costs. Ultimately this could lead to lower tariffs, an outcome the government has been pushing hard for.

In the short term the sector will continue to be dominated by fossil fuel-powered generators, and achieving targets of 20% renewables in the energy mix will depend on the economic viability of projects competing head-to-head with conventional power plants.