Oil price meltdown puts Asia’s upstream projects in jeopardy

Highlights

Australia likely to bear brunt of pre-FID project deferrals

NOCs need $57/b break-even, face 2 million b/d output cut by 2025

Citigroup downgrades China’s CNOOC and PetroChina

Singapore —
The oil price collapse is triggering capital expenditure cuts by Asia Pacific’s private and national oil companies resulting in some of the region’s largest exploration projects being put on hold or slowed significantly to save costs.

In the crosshairs are oil and gas exporters like Australia, Indonesia and Malaysia, but even integrated NOCs in the region who invest for energy security needs are mulling capex cuts, raising concerns about the future of local production that has been on the decline for years.

This week, Brent crude is headed towards $20/b, and while this is not the first rodeo for many of Asia’s largest NOCs who weathered previous downturns like the 2015 oil slump, analysts say oil companies have less room to maneuver now.

“After all the self-help of the last oil price downturn, including squeezing the supply chain, restructuring internally and divesting non-core assets, there’s probably less scope this time around for a repeat performance,” Andrew Harwood, Research Director, Asia Pacific Upstream Oil & Gas at Wood Mackenzie said.

Harwood said discretionary spend will be firmly in focus this time, and cuts will be hard and deep, while growth will be off the table for all but the most financially strong.

If all pre-FID (fixed investment decision) projects are deferred indefinitely, Asia Pacific could see a 2 million b/d reduction in supply by 2025, a reduction of more than 10% from pre-crash forecasts, he said, adding that actual declines could be higher.

Asia’s oil and gas producers have not always been the most cost efficient, but their proximity to demand centers and the need to diversify from hotspots like the Middle East still made them feasible. Oil at under $30/b changes this equation.

Asian NOCs as a peer group require around $57/b Brent break-even for 2020 and 2021 on a cash flow basis, including all their businesses, and interest and dividend payments, Maxim Petrov, Wood Mackenzie’s senior corporate research analyst, said.

“It’s relatively high compared to the overall corporate coverage that we have, about $5 higher,” he said.

IN THE CROSSHAIRS

In 2019, Australia emerged as the world’s largest LNG exporter and laid out plans for brownfields expansions and projects to replenish existing plants called backfills.

Harwood said Australia will bear the brunt of pre-FID project deferrals with key LNG-backfill projects at risk of being pushed back, such as the Scarborough and Barossa developments that were expected to be the biggest FIDs in 2020.

“Those projects accounted for $14 billion of the $27 billion in investment we expected to be sanctioned this year,” he said.

The Woodside-operated Scarborough project is designed to feed the expansion of Pluto LNG in northern Australia, and the Santos-operated Barossa development is meant to feed the Darwin LNG expansion project.

“However, with Santos, it’s estimated to require around $60/b to fund growth while maintaining current levels of debt. And with 2020 revenue at Woodside perhaps set to fall by almost 40% if [oil] prices remain at current levels, neither of these companies are going to be keen to push the go button on these projects until there’s more clarity in the direction of the oil price,” Harwood said.

Woodside and Santos did not immediately respond to queries.

Other pre-FID upstream projects likely to be put on hold are Petronas’ Kelidang Cluster in Brunei and the deep-water Limbayong oil development off Sabah in eastern Malaysia, as they were already facing delays due to complexity and regulatory hurdles, he said.

The projects that might still have a shot in 2020 are Repsol’s Sakakemang development in Sumatra or Sapura Energy’s SK408 gas fields off Sarawak as they benefit from low break evens and close proximity to infrastructure, he added.

The Sakakemang gas discovery in 2019 was the largest gas find in Indonesia in 18 years at the time, and among the 10 largest finds worldwide in the preceding 12 months, according to Repsol.

DRILLING DILEMMA

Asian NOCs will face a complex set of decisions as oil prices remain low.

Some, like India’s ONGC and China’s CNOOC and CNPC have an energy security mandate and with the current coronavirus outbreak, a need to maintain investment and support economic recovery.

Last week, Citigroup analysts downgraded PetroChina to sell and CNOOC to neutral, saying CNOOC will still remain profitable given its competitive $29/boe breakeven cost while PetroChina struggles at a higher break-even cost of $40/boe, worsened by weak gas demand.

This week, Japanese bank Nomura downgraded Thai explorer PTT Exploration & Production to neutral citing lower earnings forecasts. However, it said PTTEP has a relatively lower risk of capex cuts as its sales are dominated by gas which is stickier than crude oil and provides some stability to earnings.

Wood Mackenzie’s Petrov said Indonesia’s state-run Pertamina has a slightly lower break even than its peers at around $50-$55/b because its production sharing contracts are mostly onshore but longer term dynamics could be tricky.

Overall, Wood Mackenzie expects 200 exploration wells to be drilled in the Asia Pacific in 2020, but this is likely to fall by 30% or lower in 2021.

A key problem is that many of Asia’s largest producing fields are mature and need expensive drilling to maintain output, such as China’s Daqing oil fields, Indonesia’s Rokan block and PTTEP’s Gulf of Thailand gas fields.

“Reducing production declines at these projects while cutting spend will be nothing short of Herculean,” Harwood said.