PTTEP faces margin pressure on gas plan
As the Thai NOC embarks on its record five-year investment programme, analysts wonder how it will maintain profitability
Thailand’s NOC and largest petroleum producer PTTEP in December announced its largest-ever five-year investment programme of $24.6bn. Maintaining margins on these investments will be challenging given the gas prices it has committed to receiving for the output of its holdings in the Gulf of Thailand.
PTTEP won production and development rights for the Bongkot and Erawan fields in the Gulf of Thailand in December 2018. Chevron previously operated Erawan, while PTTEP was already the operator of Bongkot.
The company was awarded the fields based on its offered gas price of $3.55/mn Btu and profit share terms that were more favourable than those offered by Chevron, says Prateek Pandey, senior upstream analyst at Rystad Energy in Bengaluru, India. The new price is sharply lower than previous levels, between $5.5 and $6/mn Btu, and Pandey argues this will prove to be a challenge for the company.
As an indicator of profitability, notes Pandey, Chevron decreased its drilling activity in Thailand by over 100 wells between 2018 and 2019. Chevron, now locked in a dispute with the Thai government over who will pay for decommissioning at Erawan, will continue some basic Thai drilling operations until 2022 just to meet production targets, he says.
“PTTEP faces a daunting task to expand its global portfolio” Pandey, Rystad Energy
The Thai government will also be taking a larger slice of the pie at Bongkot and Erawan. Nomura analyst Ahmad Maghfur Usman in Kuala Lumpur expects the overall government take from the gas fields to be 68pc-70pc, compared with previous levels of around 50pc.
State-owned PTTEP completed the acquisition of Partex—which has assets in Oman, the UAE, Angola, Brazil and Kazakhstan—as well as Murphy Oil’s assets in Malaysia in the second half of 2019. The projected investments to 2024 “will certainly be an uphill task for PTTEP,” Pandey says. “Organisational transformation to cope with its expanding global portfolio will be one of the challenges.”
But many of the projects with more than 50mn boe of resources that Rystad expects PTTEP to sanction in the next six years are currently uncommercial, he adds. The company could therefore try to sell some of them, such as Cash-Maple in Australia, Lang Lebah in Malaysia and Ubon in Thailand, he says. Given declining reserves from its existing portfolio and slim chances of new petroleum finds in Thailand, PTTEP “faces a daunting task to expand its global portfolio”.
The strength of state-owned PTTEP’s finances is not in doubt. Sachin Muralee Krishna, equity research analyst at Country Group Securities PCL in Thailand, points to $3bn cash on the company’s balance sheet and financial backing from parent PTT. And, the offtake agreement with PTT shields the company from global gas price fluctuations.
$24.6bn - cost of PTTEP’s investment programme
But costs will be a challenge. The five-year plan shows that implied per unit operating costs will be between $11.5 and $14.5/bl oe until 2023. PTTEP management attributes this to higher operating expenditure for new assets and decommissioning costs at Bongkot in 2023. It projects that per unit operating costs will not decline until 2024, which Nomura says is based on expectations for LNG in Mozambique, where PTTEP has an 8.5pc stake in the Rovuma LNG project. This looks optimistic; ExxonMobil, in charge of onshore operations at Rovuma, does not expect it to become operational until 2025.
In the Gulf of Thailand, PTTEP is counting on improvements in drilling efficiency, the standardisation of well-head platforms and better logistics to maintain margins. But production from Bongkot and Erawan is set to taper off quickly in coming years. Pandey says the company may have to seek more acquisitions or make larger investments in mature fields and expects the company to fall short of its planned sales volume target of 437,000bl oe/d by 2023.