As Indonesia’s natural gas production continues to recede from its peak in 2009, the government is looking to boost upstream activity by proposing four high-potential oil and gas projects for the list of national strategic projects (PSN). Under this programme, which was initiated by presidential decree in 2016, infrastructure projects deemed to be of national strategic importance are fast-tracked. The four upstream oil and gas projects that were proposed for the list by the Ministry of Energy and Mineral Resources are the Tangguh liquefied natural gas (LNG) train 3, which is owned by BP Berau; the Masela block operated by Inpex; Chevron’s Indonesia Deepwater Development (IDD); and Pertamina EP Cepu’s Jambaran-Tiung Biru.

In addition to the upstream projects, three downstream oil and gas projects were previously included in the PSN list, namely the Bontang refinery in East Kalimantan, the Tuban refinery in East Java and four refinery upgrades included in the Refinery Development Masterplan Programme of Cilacap in Central Java.

TANGGUH: Producing up to 7.6m tonnes per annum (tpa) of LNG since 2009, the Tangguh LNG project is expected to increase output through the addition of a third train at its liquefaction facility. Operator and leading stakeholder BP, which in 2016 increased its interest in Tangguh from 37.16% to 40.22%, announced in July 2016 its final decision to move forward with the new 3.8m-tpa train. The investment would bring output at Tangguh to 11.4m tpa upon completion in 2020. The project requires the construction of two offshore platforms and 13 new production wells, an expanded LNG loading facility and supporting infrastructure. Some 75% of the additional LNG production from train 3 will be sold to the state electricity firm Perusahaan Listrik Negara (PLN) for power generation. Other partners in Tangguh are MI Berau (16.3%), CNOOC Muturi (13.9%), Nippon Oil Exploration (Berau) (12.23%), KG Berau Petroleum (8.56%), KG Wiriagar Overseas (1.44%) and Indonesia Natural Gas Resources Muturi (7.35%).

MASELA: Operated by Japan’s Inpex, the Masela block contains the Abadi gas field which contains proven reserves of 10.7trn cu feet of natural gas. Originally intended as a 2.5m-tpa floating LNG (FLNG) and 8400-barrels-per-day (bpd) condensate project, additional testing revealed larger reserves than previously discovered. As a result, Inpex revised its plans upwards to 7.5m tpa and condensate production of 24,000 bpd in 2015, which would make the project the largest such FLNG operation in the world.

These plans were again reviewed in 2016 to consider onshore processing alternatives, due in large part to a desire by the government to allocate some of this output for domestic use. Under the new development plan, the onshore natural gas facility will have a capacity of 9.5m tpa, nearly four times the originally intended output. Inpex began work in 2016 on a revised front-end engineering design study for the new onshore facility, with first production hoped to commence by 2026. Inpex holds a 65% majority share in the project, with Royal Dutch Shell owning the remaining 35%.

DEEPWATER DEVELOPMENT: One of the biggest question marks of the four proposed upstream PSNs is the IDD operated by Chevron, which holds a 62% stake in the project. Cost estimates for the technically challenging project have ballooned since the IDD was first proposed, causing the government to call for Chevron to revise its plans and cut costs at a time when regulators have already revised the PSC structure to essentially eliminate state responsibility for cost recovery (see analysis). The company first secured approval for the IDD’s development plan from Indonesia in 2008, based on an investment estimate of $6.7bn.

However, costs have since swollen to more than $12bn, forcing Chevron to resubmit its development plan in 2014. This has led to conflict between the state and Chevron, with the company seeking 240% of investment credit for the IDD project, and the government intending to cover no more than 100%. These credits incentivise upstream exploration and development (particularly in marginal areas) by allowing contractors to recover investment credit amounting to a certain percentage of the capital investment costs directly required for developing production facilities.

PSCs for three of the blocks within the IDD are also set to expire over the next decade: the Makassar Strait PSC expires in 2020, Rapak in 2027 and Ganal in 2028. These blocks contain five separate gas fields, Bangka, Gehem, Gendalo, Maha and Gandang, which together contain an estimated 2.3trn cu feet of gas reserves. In spite of the challenges and uncertainties surrounding the future of the IDD, initial production in the first stage of the project began in August 2016. The Bangka Project has a design capacity of 110m standard cu feet per day (scfd) of natural gas and 4000 barrels of condensate per day. A decision by Chevron regarding the second phase of development (Gehem, Gendalo, Maha and Gandang fields) looks unlikely until the status of contract extensions is resolved. Under the initial development plan, Gendalo and Gehem fields were expected to start production in 2018.

A NEW PROJECT: The fourth and final strategic upstream project could potentially supply substantial amounts of oil and gas to the central Java region by tapping into large onshore reserves in the Cepu block near the highly productive Banyu Urip oil and gas field. Located 550 km east of Jakarta, the Cepu oil and gas block on Java Island is one of Indonesia’s most storied production areas, having been active since the late 19th century. Because of this long history, the basin was considered mature until 2001 when collaboration between ExxonMobil Cepu, a local subsidiary of oil major ExxonMobil, and Pertamina discovered the highly productive Banyu Urip field. The same two firms teamed up to take on a new project adjacent to Banyu Urip in the Jambaran-Tiung Biru (JTB) unitisation field gas development project located in the district of Bojonegoro.

The Jambaran field is in the Cepu block contract area originally under ExxonMobil Cepu, while Tiung Biru field is being developed by Pertamina. Once fully operational, the project will produce an average of 315m scfd for 14.8 years without a compressor and maintain peak production through year 16 with a compressor. Initial work on the JTB project at the end of 2016 included the preparation of two well pads along with support infrastructure. These wells will be connected to a gas processing facility with a capacity of around 330m scfd, with another pipeline linking it to a Pertamina gas facility for sales and distribution.

In spite of the potential of the project, disputes over costs and gas prices arose between the government, developers and PLN, raising doubts about its development. Citing what it deemed to be high gas sale prices, upstream oil and gas regulator SKK Migas assigned a special task force in July 2017 to conduct an audit to determine if development costs could be reduced.

“At present, we’re still stuck in the monetisation process because the field’s development is too costly, resulting in a gas price of $11 per million British thermal unit (Btu). It doesn’t make sense,” Fatar Yani Abdurrahman, deputy for operation control at SKK Migas, told local media in July 2017, adding that any figure below that would be uneconomical. According to Fatar, deadlock over the gas price had yet to be resolved, with PLN willing to pay $7 per million Btu for the gas at its plant gate in Gresik, while developers want the price of $7 per million Btu at its wellhead in the JTB field.

ExxonMobil is unlikely to be a part of the project after agreeing to sell its 45% stake in September 2017.