Southeast Asian project plans scale back
Only developments with both low breakeven costs and favourable locations are likely to proceed for the foreseeable future
The prospect of a sustained low oil price environment raises questions over whether a range of development projects in Southeast Asia will proceed.
Producers in the region have not distinguished themselves in terms of cost efficiency, creating a degree of vulnerability, says Sittidath Prasertrungruang, head of research at investment firm Country Group in Bangkok.
Greater proximity to Asian demand centres than competing supply options in the Mid-East Gulf has made it feasible to operate projects with oil at around $30/bl, he says. But prospect of prices lingering below that level have “changed the whole scenario”.
Projects awaiting FID that are, in Prasertrungruang’s view, likely to be put on hold include Malaysian state-owned Petronas' Kelidang cluster in Brunei and its deepwater Limbayong oil development offshore Sabah in eastern Malaysia. These, he notes, were already facing possible delays due to their complexity as well as regulatory hurdles.
Petronas should have no issue raising financing should it wish to take the projects forward, given a $6bn offer of senior bonds this month was six times oversubscribed. But Malaysia’s February decision to revoke a cross-border agreement with Brunei to jointly develop fields on their shared maritime border will negatively impact Kelidang.
Only the most robust plans are likely to go ahead as scheduled
Even if that issue can be resolved, the development is “somewhat questionable,” says Anish Kapadia, managing director at London-based consultancy Akap Energy. A gas development should, in theory, be less affected by lower oil prices. But as Kelidang’s output would sell through Brunei LNG facilities, pricing is likely to be oil-linked, Kapadia says. Its greenfield status also means development costs are higher.
Limbayong is also likely to be delayed due to its geological complexity and the fact that it struggled to get off the ground even in a more favourable oil and gas environment, according to Kapadia. A floating production storage and offloading vessel (FPSO) contract was due to be awarded in September 2019.
But no award was made and, under current market conditions, Petronas will be “even more reluctant to take the risks of going it alone” on a complex deepwater development, says Prateek Pandey, senior analyst at consultancy Rystad Energy. FIDs for Kelidang and Limbayong could slip as far as 2024 or 2025, he says.
Survival of the strongest
Only the most robust plans are likely to go ahead as scheduled. Thailand’s PTTEP has a strong balance sheet and, given a sales portfolio dominated by gas, potentially less incentive for major capex cuts,
Prasertrungruang says. Investments in the Erawan and Bongkot fields will continue as planned, according to PTTEP management
The Sakakemang development in Sumatra, Indonesia, operated by Spain’s Repsol, and the Jerun phase of Sapura-OMV SK408 gas fields off Sarawak, Malaysia, a joint venture between Mlocal firm Sapura Enegy and Austria’s OMV, may also see material 2020 progress, he says.
$30/bl Oil price below which many projects become unfeasible
Both projects benefit from breakeven costs below $30/bl and close proximity to infrastructure. The Sakakemang discovery—potentially the largest gas find in Indonesia since the early 2000s and one of the world’s 10 largest in the last year—is 25km from the Grissik gas plant, which serves the domestic Indonesian and Singapore markets. Repsol should also benefit from strong project partners in Petronas and Japan’s Mitsui.
Assuming a conservative $3/bl oe net present value for the gas discovery implies a gross value of $1bn, according to Akap Energy data. Robust domestic gas demand, the link to Singapore and other potential export markets should support swift field development. The question mark, Kapadia says, is that Repsol is promising a €1bn capex cut for 2020, which may postpone work to take Sakakemang forward in the short-term.
Sapura-OMV's Jerun development looks more immediately investable, in Kapadia’s view. For one, it would be the second phase of an existing development, where the first phase can deliver cost recovery. The joint venture and its partner Shell should also “be in a strong enough financial position” to proceed.