As well as the having the largest economy and population in Southeast Asia, Indonesia is the region's biggest producer of crude oil and natural gas. However, lackluster investment over the last two decades coupled with rising domestic energy consumption levels have led to a worsening supply/demand situation. Indonesia already has to import significant amounts of crude oil and refined oil products and industry experts forecast that the country, the world's leading LNG exporter until as recently as 2005, will become a net gas importer within the next few years.
The good news for Indonesian oil and gas opportunities, and for technology suppliers to the sector, is that the government of President Joko Widodo intends to eliminate the oil and gas deficit and bring energy security to the country. In 2014, President Widodo was elected based on his agenda to vastly improve Indonesia's anemic infrastructure and lagging industrial performance.
Projects given the go-ahead just over the last few months include, a new $13.8 billion oil refinery (Pertamina and Rosneft) and a $5 billion refinery upgrade (Pertamina and Saudi Aramco) in East Java, and $8 billion expansion of BP's LNG plant in West Papua.
In addition, several projects that will further help boost current capacity levels and bring new production on stream are set to see approval within the next one or two years. These include Chevron's $10 billion (estimated) deepwater gas project in East Kalimantan; Inpex's $19 billion (estimated) gas project in the Arafura Sea; and multi-billion dollar upgrades to four of Indonesia's currently operating but aging oil refineries.
Indonesian Oil and Gas Industry Structure and Status
Along with national oil company, Pertamina, overseas oil giants such as Chevron, ExxonMobil, BP, and Total make up Indonesia’s oil & gas industry. The foreign entities, which established a presence in the country over the last few decades, are most visible and active in the upstream (exploration and production) segment of the industry. The downstream refining segment is handled almost exclusively by Pertamina, as is distribution of petroleum products within the country.
To protect Indonesia’s oil and gas resources while encouraging overseas investment to uncover and realize these resources for the good of the nation, foreign oil companies are required to enter into production sharing contracts (PSCs) with the Indonesian government. These contracts spell out a number of rules regarding the foreign entity’s activities in Indonesia: the permitted duration of exploration and production; the percentage split of production output between government and foreign company; and the domestic market obligation (DMO), which mandates that a certain percentage of the foreign company’s PSC share must be sold within the country rather than overseas.
The government department responsible for Indonesia's oil & gas industry is the Ministry of Energy and Mineral Resources. The Upstream Oil And Gas Regulatory Special Task Force (SKK Migas) regulates business activities for the upstream sector, while BHP Migas is the regulator for downstream.
Aside from the low oil price environment deterring new investments, the lack of regulatory clarity, which has long been an issue for foreign players in the Indonesia oil & gas industry, plus the perception of a more recent trend towards greater resource nationalism, discourages oil majors from placing bigger long-term bets in the country.
For instance, each year, the government puts up for tender a number of oil and gas "blocks" for exploration and (potential) production. In the latest round (2015 tender) eight conventional blocks were offered; however, as announced in May 2016, none were taken up.
The insufficient investment over the last 25 years has caught up with Indonesia in the form of a skewed supply/demand picture, i.e. inadequate domestic supply of crude oil in particular as well as refined products against a backdrop of rising demand levels. As a result, the country now relies on imports and lacks energy security.
However, as in other areas important to the economy (power, water, roads, rail, ports and airports, etc.) the government of Joko Widodo is determined to improve the oil & gas situation in Indonesia. To this end, it has already sanctioned billions of dollars in expenditures, with more expected.
With a 2016 target of 830,000 million barrels per day (bpd), oil production in Indonesia is now around half that of the 1.6 million bpd achieved in the mid-1990s, with contributory factors being aging oil fields and insufficient exploration. The recent oil price slump, of course, is not favorable to either exploration or production.
However, it is not all doom and gloom in the Indonesian upstream oil sector. In 2001, with the aid of high-resolution 3D seismic technology, ExxonMobil made a major discovery in its onshore Cepu block in East Java and eventually agreed to a production sharing contract that runs to 2035. Under the PSC, ExxonMobil and Pertamina each hold a 45 percent share and the remaining 10 percent belongs to four local governments.
The most prominent field and the first under production (2015) within Cepu is Banyu Urip, which contains an estimated 375-450 million bpd of recoverable reserves.
After coming on stream last year, ExxonMobil announced crude production levels of 185,000 bpd in May of this year, which constitutes more than 20 percent of the country's crude output and already exceeds the field's planned peak production target of 165,000 bpd. In fact, the US oil major also revealed recently that Banyu Urip is capable of producing more than 200,000 bpd.
In April 2016, Pertamina announced its intention to develop the Kedung Keris field within the Cepu Block some 14 km (8.7 miles) from Banyu Urip. Plans call for the construction of two wells and a pipeline to the processing facility on Banyu Urip. Production estimates are 5,000-8,000 bpd upon first oil in 2019.
With major production operations at the Duri and Minas fields on the island of Sumatra, Chevron has long been the largest oil producer in Indonesia. However, with both fields aging, the company is now using enhanced oil recovery techniques to maintain production levels.
The Duri field is now one of the world’s largest steamflood developments, and the Duri Field Area 13 steamflood expansion, which was completed in 2015, adds 17,000 bpd of oil output at peak production.
As for its oil fields in East Kalimantan, which produce 18,000 bpd, Chevron announced in January 2016 that it would not extend its PSC when it expires in 2018 and instead will return these to the government. Although the company did not cite reasons for the decision, the low oil price environment and declining reserves are likely factors.
On May 11, 2016, Pertamina revealed it would take over the East Kalimantan block upon Chevron's exit. Earlier, Pertamina announced that it intends to further develop the Sukowati oil block in East Java through its Pertamina-PetroChina East Java (PPEJ) joint venture.
Compared to crude oil, the natural gas situation in Indonesia is more positive. Proven reserves have increased over the last decade and production levels exceed domestic demand. However, that demand continues to increase making it quite likely for the country to become a net importer of gas within the few years. Hence there is a similar need to exploit new fields and boost production levels.
Currently the largest and most prominent gas field in Indonesia is the 50-year-old offshore Mahakam block in East Kalimantan. Operated by Total, in the first quarter of this year it produced 1.7 billion cubic feet per day of natural gas, well above the targeted 1.5 million bcfd. However, the French oil major has decided not to renew its PSC for the block when it expires in 2017.
Consequently, from 2018, Mahakam will be under 100 percent ownership of Pertamina. Reports indicate that $2 billion is spent yearly to sustain production at the block and Pertamina said this April that it is allocating more than $2.5 billion in expenditure for Mahakam for when it takes ownership in 2018.
Pertamina is also notably active in the aforementioned Cepu block, which also contains gas reserves as well as oil. Estimates indicate that the Jimbarang-Tiuyng Biru field will produce 185 million cfd when it comes on stream in the targeted year of 2019. Plans so far announced by Pertamina for the $2 billion project include the selection of an EPC this year followed by the commencement of drilling (five wells) in 2017.
A bone of contention this year has been the Masela block. Located in the Arafura Sea, its estimated 10.7 trillion cubic feet of reserves makes it larger than Mahakam and, at a production of 7.5 million cfd, it is expected to last for more than 20 years. Under a PSC agreement signed back in 1998, Japan's Inpex holds operating rights and 65 percent ownership, with the remaining 35 percent owned by Shell.
The original plan proposed by Inpex for the Masela block's Abadi gas field was for a $15 billon floating LNG (FLNG) facility with annual processing capacity of 7.5 million tons, making it bigger then Shell’s flagship Prelude FLNG.
This was expected to get the final go-ahead earlier this year. However, after opposition from Maritime Affairs Minister Rizal Ramli, who felt onshore processing at nearby islands would deliver greater economic benefit to the region and to the country, the FLNG plan was rejected by President Joko Widodo in March in favor of the onshore option.
While Inpex says it is committed to developing the onshore processing alternative and will prepare a new POD (Plan of Development), the decision has set back the time to first gas from Masela, which may now not happen until 2026, further increasing the chances of Indonesia becoming a net gas importer.
According to SKK Migas, an onshore facility could entail an additional $4.5 billion expenditure versus the FLNG option. Interestingly, on July 12, Pertamina confirmed its interest in acquiring 20 percent of Inpex's share in the Masela block.
Over in the Natuna Islands in the Riau Islands province off Sumatra, the East Natuna block contains even more gas reserves than Masela: 46 trillion cubic feet, which makes it not only the largest gas reserve in Indonesia but also in the entire Asian continent.
The East Natuna block is now under exploration by a consortium of companies comprising Pertamina, Thailand's PTT, and ExxonMobil, which signed the original PSC back in 1980.
One negative about the block is its high carbon dioxide level. Exploitation of the block would thus require additional expenditure and advanced technology. Estimates put the total amount required to develop the block at anywhere between $20-$40 billion. Statements from the Indonesia government indicate that it is looking to expedite East Natuna block production although there is no clear date yet as to when operations could start.
Another large gas project and one that is closer to realization is Chevron's Indonesia Deepwater Development (IDD) project, in East Kalimantan’s Kutei Basin. In 2008, Chevron obtained government approval to undertake a multi-billion-dollar venture for what would be Indonesia’s first ever deepwater gas project. The company has an 80 percent interest in the five fields – Bangka, Gehem, Gendalo, Maha and Gandang – with Italy’s Eni having 20 percent. The estimated gas reserves are 2.3 trillion cubic feet.
Initially, the Bangka field was scheduled to begin production this year, followed by the Gehem and Gendalo fields in 2018. However, in October 2014, Chevron requested permission from the Indonesian government to postpone commencement of the IDD project on the basis that it had found additional reserves that would increase the cost from $7 billion to $12 billion.
Then in June of this year, upstream regulator SKKMigas requested Chevron to relook the investment amount on the basis that $12 billion is excessive given a low energy price environment. While Chevron has expressed its commitment to continuing with the IDD project, it is now likely that gas will not come on stream until 2020.
Indonesia was the world’s leading liquefied natural gas exporter for many years, accounting for 40 percent of global LNG exports in 1987 and keeping the number one position until 2005. However, it has since slipped to seventh place, mainly because of much greater LNG infrastructure investment in countries like Qatar and Australia, and as a result of increased domestic gas consumption.
The largest facility is still the Badak LNG plant in Bontang, East Kalimantan, which was instrumental in Indonesia achieving its once-leading exporter position. The huge complex includes eight trains, six LNG tanks, and three loading docks, as well as 15 power generators and 21 boilers.
However, with peak production achieved in the 2001-2003 timeframe, the plant now only runs with four trains because of declining gas supply from nearby fields. Earlier this year, the operator, Badak LNG, said it hopes Pertamina can increase gas production from the Mahakam block it is acquiring from Total. Otherwise, only two LNG trains could remain in operation by 2019.
One LNG facility already impacted by declining gas production is the Arun plant in Aceh. At its peak, it had six trains operating each with a capacity of some two million tons per annum. After steadily declining gas supply, liquefaction operations ceased in October 2014.
However, rather than being scrapped, the Arun plant was converted to a 400 million cubic feet per day receiving and regasification terminal, at a cost of more than $60 million. After its commissioning last year, pipelines now transport the gas to industrial and power generation customers in Aceh and Sumatra.
Still, there are tangible investments to boost LNG production levels in Indonesia. The $2.9 billion, two million mpta Donggi-Senoro LNG plant in Sulawesi started production in June 2015. LNG is shipped on long-term contracts to customers in Japan and Korea, and also goes internally to the new Aceh regasification plant. And close to completion, also in Sulawesi, is the similar capacity Sengkang LNG plant. According to developer Energy World Corp, start-up is expected by the end of 2016.
Investments are also taking place at Indonesia's fourth currently operating LNG facility – BP's Tangguh plant in West Papua. Just recently, on July 1, BP announced final investment decision for its $8 billion Train 3 expansion, which will add 3.8 mtpa to bring Tangguh's capacity to 11.4 million tons per annum.
With construction commencing this Q4, the new Tangguh plant is expected to come on stream in 2020. And as well as creating an estimated 10,000 jobs in this far less developed region of Indonesia, 75 percent of its LNG output will go to state power company PLN, which is in the midst of a huge electrification drive.
Similar to the upstream situation with crude oil, Indonesia faces a supply/demand deficit in refined petroleum products, with lack of investment again being the main culprit. The last new refinery, Balongan, was built in 1994. Indonesia's current six refineries' total production of some 830,000 barrels per day (bpd) meets around only half of the 1.6 million bpd demand.
President Widodo's incoming government in 2014 recognized the urgent need to boost the country's refining capacity to cut imports, improve the trade balance, and ensure security of supply.
As outlined in Pertamina's Refinery Master Development Plan (RDMP), this capacity addition is being delivered through a combination of $25 billion refinery upgrades plus many billions more for new plant construction. The target is for domestic refining capacity to reach 2.3 billion bpd come 2025.
And a key government announcement came in December 2015 allowing for the first time foreign oil companies to construct refineries in Indonesia. Previously, the sector was restricted to state-owned Pertamina.
The Cilicap refinery in East Java is the first of the current refineries to undergo upgrading. The $5 billion project is being carried out as a joint venture between Pertamina and Saudi Aramco, with the latter providing technology and expertise as well as funds.
Following the appointment of Amec Foster Wheeler for basic engineering design this May, the Cilicap project is set to complete in 2022, delivering a refinery capacity increase of 100,000 bpd (from 270,000 to 370,000 bpd) as well as higher quality and "greener" oil products.
Other refineries targeted for upgrades are Balikpapan, Balongan, Dumai, and Plaju. A planned joint venture for upgrading of the Balikpapan refinery in East Kalimantan between Pertamina and Japan's JX Nippon fell through and Pertamina is now looking to go it alone with the estimated $5 billion project. A similar JV between Pertamina and China's Sinopec for Plaju refinery upgrading has also fallen through.
In May 2016, came news of the first new oil refinery in Indonesia in 22 years. Russia's Rosneft is partnering with Pertamina in a 45/55 percent joint venture to build the Tuban refinery in East Java. The $13.8 billion, 300,000 bpd plant is expected to be operational in 2022.
Elsewhere, the government gave the go-ahead in February for another new refinery, in Bontang, East Kalimantan. The 300,000 bpd-capacity plant, with an estimated cost of $14.5 billion, is to be built under a public-private partnership scheme. Pertamina, which is in charge of the project, is currently looking for investors and construction is targeted to commence in 2017. And a third new refinery, located in Arun, Aceh, is on the government's agenda, although no details on this are available as yet.
In 2014, there were reports of Iranian interest in the Indonesian refinery sector, including a potential tie-up with locally owned Kreasindo Resources for construction of two refineries, in Banten and West Java. However, there appears to be no progress on this initiative.
While the upstream oil sector still requires significant work and investment to overcome the current crude oil deficit in Indonesia, tangible efforts are clearly being made to renew and revitalize other segments of the oil & gas industry, notably gas production, LNG, and refining.
While issues certainly remain around the form and extent of foreign participation in the sector and finding project financing in a low-oil price environment, the multiple billions of dollars of expenditure recently announced for gas and refinery infrastructure do indicate that Indonesia is serious about upgrading its oil & gas industry, which has been neglected relative to countries like China, India, Qatar, and Australia.
The ARC Southeast Asia office will continue to track developments in Indonesia's oil & gas industry for our technology end user and supplier clients alike to help all parties generate maximum value from the significant opportunities that lie ahead.
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Keywords: Oil, Gas, LNG, Refining, Upstream, Downstream, Indonesia, ARC Advisory Group.