Diversification under way: Hydrocarbons remain a key contributor to the economy, but the energy mix is steadily broadening

The nation’s vast territorial expanse and established presence of experienced, well-financed international and domestic oil firms has led to the discovery and exploitation of a succession of sizeable oil and gas projects across the country for more than 125 years. Lured by attractive production contracts, considerable remaining reserves and strong energy prices, the country more recently has managed to mitigate the decline of its maturing oil fields and even boost overall energy output from 2007 to 2010, through increased natural gas production and a concerted effort to maximise the efficiency of its legacy fields.

This trend took a turn for the worse in 2010 when uncertainty over the interpretation of the regulatory framework of the sector came into question and the lack of stability within the oil and gas sector as a whole began to give operators – particularly international ones – pause before making new large-scale investments or even extending existing agreements.

Cash Flow

Despite efforts to diversify the economy, the energy sector remains very much a crucial contributor to government coffers. For 2012 the upstream oil and gas industry contributed $34.9bn towards state revenues, exceeding the target of the Indonesian Revised Budget of $33.48bn, according to the SKK Migas 2012 annual report. Petroleum sales accounted for a whole 58% of the government’s gross revenue stream on the year. Upstream investment in the sector continued to grow for the fourth consecutive year with 2012 inflows hitting $16.1bn, $2.1bn more than the $14bn seen in 2011. The lion’s share of 2012 funding, $13.7bn, was channelled towards activities such as staving off production declines of maturing fields, leaving $1.4bn for exploration activities with the remaining $1bn going towards administrative costs, according to SKK Migas.

Oil Reserves

As domestic oil consumption continues to outpace exploration, reserves continue to decline, with SKK Migas estimating proven oil and condensate reserves at 3.59bn barrels of oil with another potential 3.68bn barrels in the ground, as of January 1, 2013. The reserve replacement ratio (RRR) in 2012 was 52%, indicating that every barrel of oil produced was replaced by half a barrel of new discoveries. The RRR for natural gas, by contrast, paints a rosier picture, with a RRR of 127% and proven reserves of associated and non-associated gas of 104.37trn standard cu ft (tscf) along with the potential for an additional 48.38 tscf. These figures are similar to those published in BP’s “Statistical Review of World Energy 2013”, which listed Indonesia’s oil reserves at 3.7bn barrels, down from 4.7bn barrels at the end of 2002, and a reserve to production ratio of 11.1. Natural gas reserves were estimated more conservatively as well, at 103.3 tscf, compared to the 91.8 tscf estimated at the end of 2002.


Mirroring global energy composition as a whole, Indonesia’s hydrocarbon output can be broadly characterised as a continued and steady decline of oil output from maturing fields offset by enhanced oil recovery efforts as well as an increase in natural gas production.

“Oil and gas exploration and production is shifting from western to eastern Indonesia, from onshore to offshore and the deep sea area. This means that we have to provide more sophisticated and bigger horsepower vessels to serve these deeper sea operations. The funds that we will be able to raise to procure these vessels will determine our capacity to grow and support our customers,” Eddy Kurniawan Logam, president director of Logindo Samudramakmur, told OBG. Yet in spite of efforts to reverse these trends, both oil and natural gas production have been in decline since 2010 as new exploration and production efforts continue to be outpaced by rising consumption. “With the amount of new discoveries occurring in deep water and marginal fields, it becomes essential for Indonesia to leverage technology and expertise from overseas to develop these challenging fields economically so to support the growth of the country,” R S Kumar, president director of Technip in Indonesia, told OBG.

While Indonesia is facing the challenges of increased costs of working maturing oil fields and the development of frontier, deepwater and unconventional resources as well as a shortage of drilling rigs and associated manpower, the opacity of the country’s energy regulatory environment is often cited as the primary difficulty for companies operating in the sector. Excepting a one-off anomaly in 2008, domestic crude oil output has decreased each year since the beginning of the millennium and has dropped from 1272 thousand barrels of oil equivalent per day (mboepd) in 2000 to 762.82 mboepd – 860 mboepd including condensates – in 2012, according to SKK Migas. The overall curtailing of hydrocarbon production from 2572.72 mboepd to 2315.18 mboepd over the same time period has been blunted by higher natural gas production which increased from 1160.42 mboepd in 2000 to 1581.59 mboepd in 2010, but has since dropped off to 1455.27 mboepd in 2012.

This is slightly less than BP estimates, which projected production at 918,000 barrels per day (bpd) in 2012, down 3.9% from 952,000 the previous year. For natural gas BP estimated domestic output of 71.1bn cu metres (bcm) on the year, down 6.6% from 75.9 bcm in 2011. The majority of this production was derived from established wells, although two new contract areas – Tonga and Pameran – did enter into production starting in 2012 after securing the requisite plan of development (PoD) approval from the Ministry of Energy and Mineral Resources (MEMR). According to the PoDs filed, the two new contract areas (CA) are projected to produce roughly 1500 bpd combined in 2013. Through September 2013, oil production averaged 202,000 bpd along with natural gas output of 260,000 boe/d, according to the state-owned energy company Pertamina.

Affecting Output

A tailing off of output by major international oil firms had a significant impact on the sector as output from ConocoPhillips Indonesia fell by 15,995 bpd (18.2% of production) from 2012 to 2011 along with a 14,615 bpd drop from Total E&P Indonesie (down 17.9%) and a host of others including ExxonMobil Oil Indonesia (-12%), Pertamina Hulu Energi West Madura Offshore (-16.1%), PetroChina International Bermuda (-15.2%), Chevron Pacific Indonesia (-4.5%) and Chevron Indonesia (-3.8%). All told, only 15 active production sharing contracts (PSCs) increased their output from 2011 to 2012, led by Hess (Indonesia-Pangkah) with an increase of 4951 bpd, . Pertamina EP (3203 bpd) and JOB Pertamina-Talisman Jambi Merang (2891 bpd). Total production continued to fall in 2013, with SKK Migas estimating in July 2013 that total crude and condensate output on the year would average 834,000 bpd, down from initial target of 840,000 bpd. After averaging 831,700 bpd through the first six months of 2013 production is projected to pick up in the second half of the year as the result of higher production from the West Madura Offshore field.

A total of 308 oil and gas contract areas were active in 2012, divided into 75 tenements in the production phase (60 producing contracts and 15 in developmental stages) and 233 in the exploratory stage, according to SKK Migas. Of the production contracts, 36 were located onshore and 24 offshore with the remaining 15 straddling both. These were further augmented by another 54 coal bed methane (CBM) contracts, nearly all located onshore. Another 18 contracts were in the process of being relinquished on the year. The 308 CAs in 2012 bested the 287 CAs active in 2011 (172 exploration, 73 production and 42 CBM), as well as the 245 in 2010 (155 exploration, 67 production and 23 CBM). As stipulated in the 2001 Oil and Gas Law, the split between the central government and oil and gas contractors is 85% and 15%, respectively, for oil production, and 70% and 30% for natural gas.


Indonesia is at a crossroads in its future domestic production prospects. Looking at the recent history of exploration activity in the country there is reason for optimism as past efforts by the regulator have yielded an increase in exploratory wells drilled each year since 2008 with a relatively consistent showing throughout the past decade. In 2012, 96 new exploratory wells were drilled across the country – 55 onshore and 41 offshore – up from 81 drilled the previous year, according to SKK Migas. The results of the 2012 efforts included 60 wildcat wells, of which 27 contained hydrocarbons: nine oil and gas discovery wells; 13 gas discovery wells; and five oil discovery wells. The outlying 36 wells are classified as delineation wells – supplementary wells drilled successively outward from an original successful wildcat well in order to determine the boundaries of the productive formation. Investment in these areas reflected the increased activity in oil and gas exploration in 2012, where investments of $1.4bn roughly doubled 2011 levels of $719m and were well above the annual 2007-11 average of $605.6m. Although 2012 saw an increase of exploratory wells drilled throughout the country, these efforts are attributed to the continuation of efforts launched years before and are unlikely to continue to be sustained as these programmes wind down and are not replaced by new activity.

The frequency of seismic surveys, for instance, has declined over the past few years. After rapidly increasing from 11,775 km of 2D surveys in 2007 to 33,906 km in 2010, these exploratory efforts plummeted to just 12,549 km in 2011 and 13,995 km carried out by 27 PSCs in 2012, according to SKK Migas data. More expensive and more accurate 3D surveys have also tailed off from 8900 sq km in 2010 to 8147 sq km and 6165 sq km in 2011. Looking ahead, SKK Migas announced in September 2013 details for the next round of bidding for oil and gas contracts, which will include tendering out 18 blocks, with applications due by January 27, 2014. The areas officered up for bidding – two through the regular tender process and 16 through direct offer – consist of both offshore, onshore and combined territory and are located primarily around central and East Java, Sulawesi and Maluku with other outlying blocks situated in south Sumatra, Papua and south of Nusa Tenggara Timur.


Among the most prolific LNG-exporting nations in the world, Indonesia’s gas infrastructure has been traditionally geared towards exploiting its domestic energy reserves firstly to bolster government coffers, with domestic consumption coming second. In 2012 Indonesia’s LNG exports of 25 bcm of natural gas shipped ranked it fifth behind Qatar (105.4 bcm), Malaysia (31.8 bcm), Australia (28.1 bcm) and Nigeria (27.2 bcm), according to BP’s “Statistical Review of World Energy 2013”. As domestic consumption has climbed and oil production waned, this strategy is being reoriented to secure fuel for electricity generation and industrial use. This shift has seen the volume of domestic natural gas consumed in 2012 reach 3.4bn British thermal units (btu) per day, up 262% from 2003 when consumption was 1.5bn btu per day, according to SKK Migas data. Exports have declined from 4.4bn btu to 3.6bn btu although exports spiked to more than 4bn btu in 2010 and 2011.

Local Focus

Outside of the domestic market obligations (DMO) written into PSCs, investors in the past had little motivation to sell on the local market which is regulated at a substantially lower price than on the regional LNG market. This issue has been alleviated in recent years by the regulator’s efforts to facilitate a renegotiation in domestic purchase price which has brought price levels closer to export parity along with considerations for transportation costs and possible LNG investments. This trend continued into 2012 as the average gas purchase price rose by 28.76%, from the 2012 APBN-P target of $8.23 per million British thermal unit (mbtu) to $10.59/mbtu, through the renegotiation of local gas prices and transfers of LNG Tangguh Papua sales, according to SKK Migas. In spite of these efforts, the average domestic gas price retreated to $5.6/mbtu by mid-2013 while export prices hovered at $14.5/mbtu according to SKK Migas, although the regulator indicated it was considering increasing the domestic price to at least $8/mbtu.

Ultimately, the development of new gas resources will be crucial in maintaining production as output has fallen in each of the past three years, dropping from 8857m standard cu feet per day (mmscfd) to 8415 mmscfd and 8167 mmscfd from 2010 to 2012, according to SKK Migas. This decline reflects a fall in production from the country’s largest producers including Total E&P Indonesia, which saw production decrease by 442 mmscfd from 2011 to 2012 along with numerous other operators. To date, the country’s key gas producing areas are situated primarily in Aceh, onshore Sumatra, offshore West Java and offshore East Kalimantan with the largest reserves estimated at 51.46 tscf and 24.32 tscf located in the South Natuna Sea and offshore Papua.

New Plays

With regards to recently added capacity, the gas deliveries from the Ruby field located in the Makassar Straits, offshore East Kalimantan began in October 2013. Operated by Abu Dhabi’s Mubadala Petroleum subsidiary Pearl Oil, production of the field is projected to reach 100 mmscfd and be delivered to Pupuk Kalimantan Timur’s fertiliser plant via a 312-km pipeline to Total's Senipah onshore gas processing plant. Other partners in the block are Total E&P Sebuku (15%) and Japan's Inpex (15%).

Progress was also made by Mobil Cepu at its Banyu Urip field, with the project increasing the production of oil from early production facility to 28,500 bpd starting October 2013. This represents 6200 bpd increase from the recent 2012 production levels and a total of 8500 bpd from its original design capacity of 20,000 bpd in 2009. Chevron Indonesia’s Indonesian Deepwater Development (IDD) project is expected to deliver an additional peak production of 924 mmscfd of gas and 23 thousand barrels of condensates per day (mbcpd) from the Gendalo, Maha, Gandang, Gehem, and Bangka fields by 2017. Other projects under way include the Adabi field being worked by Inpex Masela with reserves projected at 6-9 tcf which is scheduled to start its 30-year production run in 2017 and will include a 2.5m tonnes per annum floating liquid natural gas (FLNG) plant; the Jangkrik project, targeting 913 bcf of gas and 739 mbcpd of condensates within the Jangkrik and Jangkrik NE fields starting in 2015, developed by Eni Muara Bakau; the Bukit Tua field operated by Petronas Carigali Ketapang II, with a 20,000 bpd and 70 mmscfd capacity production facility slated to begin operations in late 2014; the Ande Ande Lumut (AAL) field operated by AWE (Northwest Natuna), the first project developed in the Northwest Natuna block with an estimated peak production of 25,000 bpd and initial output projected for late 2014; the North Duri Field operated by Chevron Pacific Indonesia, with a peak production rate gearing up to 17,000 bpd of oil in 2017 after initial flows begin in December 2013; the Kepodang field operated by PC Muriah and expected to produce 365 bcf of cumulative gas with a flow rate of 116 mmscfd of gas for 12 years starting in October 2014.


Building on its robust LNG export infrastructure, Indonesia is in the midst of a substantial expansion campaign which will see a dramatic increase in both shipping and receiving terminals across the country. As the country shifts its primary energy mixture away from coal and oil, the flexibility achieved through the addition of regasification terminals as well as new liquefaction capacity will provide opportunities both for increased consumption of domestic gas as well as export opportunities depending on how future domestic market obligation policies play out. While some production from existing LNG facilities such as Bontang and Arun is projected to tail off over the next decade, losses such as these are expected to be more than made up by the bevy of new LNG plants scheduled to start up in the coming years.

One of the more interesting projects is the retasking of the country’s oldest LNG plant of Arun, which at one time operated six trains of LNG capacity, into a receiving regasification terminal by November 2014 as local natural gas supplies are expended and the last of its contracts expire. Existing distribution from the facility will be extended through the Arun-Belawan pipeline totalling approximately 160 km in length. The 2.5m-tonne third-party access Donggi Senoro LNG project (DSLNG) which will source gas from the Senoro (producing 310 mmscfd), Donggi (50 mmscfd) and Matindok (55 mmscfd) fields is also under construction and on schedule to begin operations in the fourth quarter of 2014. Located in southwest Sulawesi, the project is being developed by a consortium that is led by Sulawesi LNG Development (itself a partnership between Mitsubishi and Kogas), with a 59.9% stake, along with Pertamina Hulu Energi with 29% and Medco LNG Indonesia with 11.1%. Additional gas from the project will be dedicated for use by Indonesia’s state electricity company PLN for electricity generation as well as for feedstock in fertiliser plants.

Train Growth

Capacity at existing facilities is also being boosted, with plans to add a third 3.8m tonnes per annum (tpa) LNG train to the Tangguh facility and boost the overall capacity of the plant to 11.4 mtpa. Construction on a new $12.1bn train is expected to begin in 2014 with the project scheduled to come online in 2018. Operated by majority stakeholder BP with a 37.16% share in the project along with MI Berau B.V. (16.30%), China National Offshore Oil Corporation (13.90%), Nippon Oil Exploration (Berau) (12.23%), KG Berau/KG Wiriagar (10.00%), LNG Japan Corporation (7.35%), and Talisman (3.06%), the plan calls for 40% of the output from the third train be reserved for PLN for use on the domestic market. With export and domestic consumption of Indonesian gas now roughly equal, the country is also moving ahead with plans to provide regasification terminals in order to counter regional shortfalls in the main demand areas of Java and South Sumatra. In addition to the Arun project and the Regas Satu terminal already in operation serving West Java, floating storage and regasification units are also projected to start operations in East-Central Java and South Sumatra in 2014.


Indonesia’s large population base coupled with a rapidly expanding economy over the past few years and substantial fuel subsidies has fostered strong growth in primary energy consumption across the board. This trend, along with minimal investment in new refining capacity over the past few decades, has resulted in an increase in imported refined products for domestic demand.

According to a report by Wood Mackenzie in September 2013, the growing shortfall will cause Indonesia to surpass the US as the world’s largest importer of petrol by 2018 – 10 years after it surrendered its position within OPEC. The report estimates the Indonesian petrol deficit will grow from 340,000 bpd to around 420,000 bpd by 2018, while the US/Mexico markets will see their shortage dwindle from 560,000 bpd to just 60,000 bpd. According to Eddy Kurniawan Logam, president director of Logindo Samudramakmur, “Going forward, Indonesian exploration and production has to grow faster to keep up with the ever increasing domestic demand.”

Dominant Player

In spite of the liberalisation of the sector in 2001, the downstream segment remains dominated by state-owned Pertamina, which owns and operates six refineries throughout the country, with a combined total capacity of just over 1m bpd. These include the Dumai-Sei Pakning refinery located in Central Sumatra with a capacity of 170,000 bpd, the Plaju refinery in South Sumatra at 127,200 bpd, Cilicap in southern Java (348,000 bpd), Balikpapan in Kalimantan (260,000 bpd), Balongan in West Java (125,000) and Kasim in West Papua (10,000 bpd). Pertamina is also carrying out an upgrade project at the cost of $7bn for its existing refineries. The project focuses on the Balongan, Cilacap, Balikpapan, Plaju and Dumai facilities, which is expected to boost total capacity to 1.2m bpd between 2015 and 2018.

Overcoming Supply Gaps

To bridge the supply gap, which currently requires importing up to 400,000 bpd of finished products each year, the government is looking to add around a half million barrels per day to its refining capacity – roughly half of Indonesia’s current capacity. As of 2013, new projects were still in the early stages of development and had not proceeded past the licensing stages for new refineries to be located in East Java, South Sumatra, Lombok and South Sulawesi. In 2013 Pertamina has focused on jointly developing at least two new refineries with experienced partners from the Middle East. The first of the two 300,000 bpd refineries is to be built in partnership with the Kuwait Petroleum Corporation (KPC) in Balongan while the second facility will be developed in conjunction with Saudi Aramco Asia Company and located in Tuban, East Java, according to Pertamina. Although the Saudi and Kuwaiti firms are signed on as technical partners, Pertamina has indicated that it still plans to carry out a tendering process for the projects. The company announced a feasibility study for the $6bn Pertamina–KPC project was completed in August 2013 following the February signing of a memorandum of understanding for an $8bn refinery with Saudi Aramco for which feasibility studies were still ongoing as of late 2013. In spite of the progress made on these undertakings, both of which could be scheduled to come online by 2018, a number of significant obstacles still remain in the form of ongoing negotiations between the potential partners. The negotiations centre around the subject of incentives for the projects, including of exemption from corporate income tax, Custom’s tax and infrastructure development. Coordinating Economic Minister Hatta Rajasa also stated in September 2013 that another refinery project slated to come online by 2018 was also under development that would be state-funded and operated solely by Pertamina with crude sourced from Iraq. Pertamina is also a partner in developing the West Qurna-1 oilfield in Iraq, which is anticipated to be a possible source of inputs. “It is time for the government, members of parliament and all of the country’s leaders to formulate the national energy roadmap in order to optimise the country’s energy resources,” Logam, president director of Logindo Samudramakmur, told OBG.


Although Indonesia may never be able to reclaim its OPEC status, which was forgone in 2008 when it became a net importer of oil, both the country’s untapped conventional and unconventional reserves have the potential to significantly ease the country’s energy import bill. Exploring and exploiting new oil and gas fields – including more expensive plays such as shale gas, CBM, deepwater and frontier resources – will be increasingly important for both the growing domestic market as well as lucrative exports as maturing legacy fields continue to decline in productivity. The success of these efforts relies not only on the technical capabilities of the oil and gas operators in the country, but also on the creation of a stable regulatory framework to restore their confidence.


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The Report: Indonesia 2014

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