President and CEO Dwi Soetjipto was forced to vacate his position, along with his Deputy President and Deputy CEO Ahmad Bambang. When announced last week, rumours circulated that the two were part of a cull linked to corruption – sadly not uncommon in Indonesia – but the truth is more sanguine. The two simply did not get along, and their disagreements were detrimental to a state oil behemoth struggling to implement the government’s ambitious energy goals.
Soetjipto was named to Pertamina’s top job in November 2014 by President Joko Widodo. Coming from another state player – cement firm Semen Indonesia where he had successfully merged three smaller ailing state firms into a renewed force – Soetjipto was criticised for his lack of experience in oil and gas, but seen as a emblem of Widodo’s will to reform the energy sector by reducing subsidies, eliminating corruption and kickstarting a moribund industry. Perhaps as a counterbalance, Ahmad Bambang was named Deputy CEO in October 2016 by State-Owned Entreprises Minister Rini Soemarno, a mere three months ago. Bambang was a career Pertamina man, seen as more in line with the existing state oil and gas bureaucratic machinery than Soetjipto.
Both immediately began to butt heads. Bambang overstepped his position by signing off on gasoline imports that were being put off by Soetjipto, a breach of authority. The two also disagreed on key position appointments, leaving important roles like the president director of Pertamina Gas unfilled. Corporate disagreements are not uncommon, but the situation between Soetjipto and Bambang was getting toxic, leading up to their dismissals by the Pertamina board of commissioners and the Ministry of State-owned Entreprises.
The spat comes at a difficult time for Pertamina, struggling to manage upstream production while hitting dead-ends on raising domestic refining capacity. Pertamina’s crude production is declining – forcing it out of OPEC for a second time last November as it could not implement supply cuts - but wants to nearly triple its upstream output by 2025, focusing on jumpstarting domestic fields and hunting for overseas assets. Meanwhile, growing fuel demand is leading to a reliance on expensive exports, as Pertamina’s grand plan to upgrade/build new refineries has stalled. Some progress had been made under Soetjipto, but just last month, Saudi Aramco pulled out of the Dumai project, while Pertamina admitted it may have to undertake the Balongan upgrade alone.
Pertamina’s board is hoping that a new management structure will help speed up things. Yenni Andayani, director for gas and renewable energy, has been named as acting CEO, while the government searches for a new leader by early March. The position of Deputy CEO will be abolished, centralising power in the new CEO, and a streamlining of the company’s 20 existing strategic positions may be implemented. Which raises the question: if the issue was the clash of personalities, why fire both? Soetjipto was a Widodo appointee, so removing him and promoting Bambang would have seemed like an usurpation, but retaining Soetjipto and removing Bambang was not an option as the state energy machinery still viewed the former as an outsider. So both heads had to fall.
This recent development will certainly colour the search for a new CEO, almost certainly to be an executive already rooted within Pertamina. But uneasy lies the head that wears the crown, and the new CEO will step into a some very large boots because the challenges facing Pertamina are vast.
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
Headlines of the week
Midstream & Downstream
Risk and reward – improving recovery rates versus exploration
A giant oil supply gap looms. If, as we expect, oil demand peaks at 110 million b/d in 2036, the inexorable decline of fields in production or under development today creates a yawning gap of 50 million b/d by the end of that decade.
How to fill it? It’s the preoccupation of the E&P sector. Harry Paton, Senior Analyst, Global Oil Supply, identifies the contribution from each of the traditional four sources.
1. Reserve growth
An additional 12 million b/d, or 24%, will come from fields already in production or under development. These additional reserves are typically the lowest risk and among the lowest cost, readily tied-in to export infrastructure already in place. Around 90% of these future volumes break even below US$60 per barrel.
2. pre-drill tight oil inventory and conventional pre-FID projects
They will bring another 12 million b/d to the party. That’s up on last year by 1.5 million b/d, reflecting the industry’s success in beefing up the hopper. Nearly all the increase is from the Permian Basin. Tight oil plays in North America now account for over two-thirds of the pre-FID cost curve, though extraction costs increase over time. Conventional oil plays are a smaller part of the pre-FID wedge at 4 million b/d. Brazil deep water is amongst the lowest cost resource anywhere, with breakevens eclipsing the best tight oil plays. Certain mature areas like the North Sea have succeeded in getting lower down the cost curve although volumes are small. Guyana, an emerging low-cost producer, shows how new conventional basins can change the curve.
3. Contingent resource
These existing discoveries could deliver 11 million b/d, or 22%, of future supply. This cohort forms the next generation of pre-FID developments, but each must overcome challenges to achieve commerciality.
Last, but not least, yet-to-find. We calculate new discoveries bring in 16 million b/d, the biggest share and almost one-third of future supply. The number is based on empirical analysis of past discovery rates, future assumptions for exploration spend and prospectivity.
Can yet-to-find deliver this much oil at reasonable cost? It looks more realistic today than in the recent past. Liquids reserves discovered that are potentially commercial was around 5 billion barrels in 2017 and again in 2018, close to the late 2030s ‘ask’. Moreover, exploration is creating value again, and we have argued consistently that more companies should be doing it.
But at the same time, it’s the high-risk option, and usually last in the merit order – exploration is the final top-up to meet demand. There’s a danger that new discoveries – higher cost ones at least – are squeezed out if demand’s not there or new, lower-cost supplies emerge. Tight oil’s rapid growth has disrupted the commercialisation of conventional discoveries this decade and is re-shaping future resource capture strategies.
To sustain portfolios, many companies have shifted away from exclusively relying on exploration to emphasising lower risk opportunities. These mostly revolve around commercialising existing reserves on the books, whether improving recovery rates from fields currently in production (reserves growth) or undeveloped discoveries (contingent resource).
Emerging technology may pose a greater threat to exploration in the future. Evolving technology has always played a central role in boosting expected reserves from known fields. What’s different in 2019 is that the industry is on the cusp of what might be a technological revolution. Advanced seismic imaging, data analytics, machine learning and artificial intelligence, the cloud and supercomputing will shine a light into sub-surface’s dark corners.
Combining these and other new applications to enhance recovery beyond tried-and-tested means could unlock more reserves from existing discoveries – and more quickly than we assume. Equinor is now aspiring to 60% from its operated fields in Norway. Volume-wise, most upside may be in the giant, older, onshore accumulations with low recovery factors (think ExxonMobil and Chevron’s latest Permian upgrades). In contrast, 21st century deepwater projects tend to start with high recovery factors.
If global recovery rates could be increased by a percentage or two from the average of around 30%, reserves growth might contribute another 5 to 6 million b/d in the 2030s. It’s just a scenario, and perhaps makes sweeping assumptions. But it’s one that should keep conventional explorers disciplined and focused only on the best new prospects.
Global oil supply through 2040
Things just keep getting more dire for Venezuela’s PDVSA – once a crown jewel among state energy firms, and now buried under debt and a government in crisis. With new American sanctions weighing down on its operations, PDVSA is buckling. For now, with the support of Russia, China and India, Venezuelan crude keeps flowing. But a ghost from the past has now come back to haunt it.
In 2007, Venezuela embarked on a resource nationalisation programme under then-President Hugo Chavez. It was the largest example of an oil nationalisation drive since Iraq in 1972 or when the government of Saudi Arabia bought out its American partners in ARAMCO back in 1980. The edict then was to have all foreign firms restructure their holdings in Venezuela to favour PDVSA with a majority. Total, Chevron, Statoil (now Equinor) and BP agreed; ExxonMobil and ConocoPhillips refused. Compensation was paid to ExxonMobil and ConocoPhillips, which was considered paltry. So the two American firms took PDVSA to international arbitration, seeking what they considered ‘just value’ for their erstwhile assets. In 2012, ExxonMobil was awarded some US$260 million in two arbitration awards. The dispute with ConocoPhillips took far longer.
In April 2018, the International Chamber of Commerce ruled in favour of ConocoPhillips, granting US$2.1 billion in recovery payments. Hemming and hawing on PDVSA’s part forced ConocoPhillips’ hand, and it began to seize control of terminals and cargo ships in the Caribbean operated by PDVSA or its American subsidiary Citgo. A tense standoff – where PDVSA’s carriers were ordered to return to national waters immediately – was resolved when PDVSA reached a payment agreement in August. As part of the deal, ConocoPhillips agreed to suspend any future disputes over the matter with PDVSA.
The key word being ‘future’. ConocoPhillips has an existing contractual arbitration – also at the ICC – relating to the separate Corocoro project. That decision is also expected to go towards the American firm. But more troubling is that a third dispute has just been settled by the International Centre for Settlement of Investment Disputes tribunal in favour of ConocoPhillips. This action was brought against the government of Venezuela for initiating the nationalisation process, and the ‘unlawful expropriation’ would require a US$8.7 billion payment. Though the action was brought against the government, its coffers are almost entirely stocked by sales of PDVSA crude, essentially placing further burden on an already beleaguered company. A similar action brought about by ExxonMobil resulted in a US$1.4 billion payout; however, that was overturned at the World Bank in 2017.
But it might not end there. The danger (at least on PDVSA’s part) is that these decisions will open up floodgates for any creditors seeking damages against Venezuela. And there are quite a few, including several smaller oil firms and players such as gold miner Crystallex, who is owed US$1.2 billion after the gold industry was nationalised in 2011. If the situation snowballs, there is a very tempting target for creditors to seize – Citgo, PDVSA’s crown jewel that operates downstream in the USA, which remains profitable. And that would be an even bigger disaster for PDVSA, even by current standards.
Infographic: Venezuela oil nationalisation dispute timeline