In a double blow to Indonesia’s attempt to boost its natural gas production, supermajor ExxonMobil and Thailand’s national oil company, PTTEP have both pulled out of the East Natuna project within days of each other last week. This leaves state oil firm Pertamina as the only player left in Southeast Asia’s largest undeveloped gas resource; a role that it cannot afford to undertake alone.
In a statement, PTTEP said that ‘under current production sharing contract terms and market conditions, commercialising the hydrocarbon resources in this area would be difficult,’ as it confirmed its pullout after the results of a Technology and Market Review (TMR). ExxonMobil’s statement was more terse – stating in a letter to the Indonesian authorities that East Natuna was ‘uneconomical for the company under current terms.’
There are two ways reading into those statements. The first is the market conditions are tough. East Natuna is located on the southern edge of the South China Sea, where the border between Malaysia and Indonesia kinks upwards unexpectedly. Not only is this area isolated (and claimed by China), it is also far away from any existing infrastructure – requiring either a floating production unit or long pipelines, both of which will be expensive. The payoff was once worth it – reserves at East Natuna are estimated at 222 tcf, of which at least 46 tcf is recoverable. But high carbon dioxide content (exceeding 70%) requires expensive processing that needs significant capex. With an estimated price tag of at least US$40 billion, East Natuna needs LNG prices of US$10-15/mmBtu to break even – and that’s hard to justify when Asian spot prices are now languishing at US$6/mmBtu.
The second is more pointed – the ‘current production sharing contract terms.’ Under the current Indonesian PSC structure, natural gas producers have to meet a Domestic Market Obligation (DMO) – that at least 25% of the production must be supplied to the local market. There is leeway for the government to demand more if the need arises. That is a huge chunk of output taken away from any project. Upstream producers in Indonesia have long championed reform to the DMO, arguing that it stifles investment. But Indonesia needs the DMO as well – its domestic consumption is growing and its argument is that Indonesian resources should also stay in Indonesia instead of being exported; at subsided prices, of course.
The first can change, depending on market conditions, but money is on LNG prices in Asia to remain below the range required by East Natuna, with the tsunami of Australian, American and Canadian LNG on its way. The second is tougher – the Indonesian government has tried for years to streamline its PSC structure to balance both domestic requirements and stimulating investment. But it will have to, sooner of later, if it wants to reverse the chronic decline in Indonesia upstream output. In the meantime, the long-running East Natuna project has claimed two other victims. Discovered in 1973, the first PSC to develop it was formed by Pertamina and pre-merger Exxon. Over the next four decades, Petronas and Total would be involved in various other attempts to commercialise the discovery, with ExxonMobil and PTTEP now giving up as well. ExxonMobil did offer an olive branch, stating that it would help with technology and technical assistance if needed. Indonesia replied that it might make a ‘special incentive’ to keep the project viable. That would have to be a very special incentive indeed; but given projected market conditions, possibly still far from enough to keep the project alive. East Natuna remains a pipe dream, for now.
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Headline crude prices for the week beginning 11 February 2019 – Brent: US$61/b; WTI: US$52/b
Headlines of the week
Midstream & Downstream
Global liquid fuels
Electricity, coal, renewables, and emissions
2018 was a year that started with crude prices at US$62/b and ended at US$46/b. In between those two points, prices had gently risen up to peak of US$80/b as the oil world worried about the impact of new American sanctions on Iran in September before crashing down in the last two months on a rising tide of American production. What did that mean for the financial health of the industry over the last quarter and last year?
Nothing negative, it appears. With the last of the financial results from supermajors released, the world’s largest oil firms reported strong profits for Q418 and blockbuster profits for the full year 2018. Despite the blip in prices, the efforts of the supermajors – along with the rest of the industry – to keep costs in check after being burnt by the 2015 crash has paid off.
ExxonMobil, for example, may have missed analyst expectations for 4Q18 revenue at US$71.9 billion, but reported a better-than-expected net profit of US$6 billion. The latter was down 28% y-o-y, but the Q417 figure included a one-off benefit related to then-implemented US tax reform. Full year net profit was even better – up 5.7% to US$20.8 billion as upstream production rose to 4.01 mmboe/d – allowing ExxonMobil to come close to reclaiming its title of the world’s most profitable oil company.
But for now, that title is still held by Shell, which managed to eclipse ExxonMobil with full year net profits of US$21.4 billion. That’s the best annual results for the Anglo-Dutch firm since 2014; product of the deep and painful cost-cutting measures implemented after. Shell’s gamble in purchasing the BG Group for US$53 billion – which sparked a spat of asset sales to pare down debt – has paid off, with contributions from LNG trading named as a strong contributor to financial performance. Shell’s upstream output for 2018 came in at 3.78 mmb/d and the company is also looking to follow in the footsteps of ExxonMobil, Chevron and BP in the Permian, where it admits its footprint is currently ‘a bit small’.
Shell’s fellow British firm BP also reported its highest profits since 2014, doubling its net profits for the full year 2018 on a 65% jump in 4Q18 profits. It completes a long recovery for the firm, which has struggled since the Deepwater Horizon disaster in 2010, allowing it to focus on the future – specifically US shale through the recent US$10.5 billion purchase of BHP’s Permian assets. Chevron, too, is focusing on onshore shale, as surging Permian output drove full year net profit up by 60.8% and 4Q18 net profit up by 19.9%. Chevron is also increasingly focusing on vertical integration again – to capture the full value of surging Texas crude by expanding its refining facilities in Texas, just as ExxonMobil is doing in Beaumont. French major Total’s figures may have been less impressive in percentage terms – but that it is coming from a higher 2017 base, when it outperformed its bigger supermajor cousins.
So, despite the year ending with crude prices in the doldrums, 2018 seems to be proof of Big Oil’s ability to better weather price downturns after years of discipline. Some of the control is loosening – major upstream investments have either been sanctioned or planned since 2018 – but there is still enough restraint left over to keep the oil industry in the black when trends turn sour.
Supermajor Net Profits for 4Q18 and 2018
- 4Q18 – Net profit US$6 billion (-28%);
- 2018 – Net profit US$20.8 (+5.7%)
- 4Q18 – Net profit US$5.69 billion (+32.3%);
- 2018 – Net profit US$21.4 billion (+36%)
- 4Q18 – Net profit US$3.73 billion (+19.9%);
- 2018 – Net profit US$14.8 billion (+60.8%)
- 4Q18 – Net profit US$3.48 billion (+65%);
- 2018 - Net profit US$12.7 billion (+105%)
- 4Q18 – Net profit US$3.88 billion (+16%);
- 2018 - Net profit US$13.6 billion (+28%)