By George Barber
This is an article that I wrote recently that was published in the Jakarta Post on 31 July 2017.
There can be no doubt about the potential of Indonesia’s Energy Potential, although potential is exactly what it is. There can also be no doubt that there is a lot happening outside of the main energy sectors that are well known, i.e., oil, gas, geothermal, hydropower, some companies are going quietly about their business and trying to develop extremely complicated fields, not so much in the resource aspects, but in the geological and environmental aspects as well as the community and battling away at the regulations.
All resource developments have their own unique challenges, especially resources that are located offshore or in onshore remote parts of this divest archipelago, most people in the resource industry accepts these challenges, these challenges can and must be met head on as part of the stages to reach the end goal, which is delivery of a resource to the end user which is commercially viable as well as ensuring that the local community’s and the county benefits.
There have been three articles published in the Jakarta Post recently that have caught my eye as follows: “Rising fuel imports stifle Pertamina”, “RI lags behind peers in renewable energy”, “ExxonMobil exit warning of waning oil, gas industry”. Surely these three headlines alone say something? Another headline stated, “Geothermal power requires incentives”. There was a publication from the Indonesian Petroleum Association (IPA) for the 41st IPA that indicated that the number of licenses required for oil and gas development had increased from 341 in 2015 to 373 in 2017 with the main increases coming from MEMR 74 (52), Transportation Ministry 76 (58), Navy 9 (2), only 4 ministries/agencies from 19 had decreased their requirements, some remained the same.
We have seen recently several companies’ that have decided enough is enough, company’s such as Marathon, Andarko, Hess and now ExxonMobile, all of these companies and more have worked in what is considered far more difficult countries to develop a business, such as Nigeria which appears to be coming more attractive than Indonesia. Every country has its ups and downs, although in Indonesia we have been seeing a steady decline of the oil & gas industry in Indonesia for many years, we can also argue the same for the mineral resource sector, the geothermal sector is struggling to gain momentum. Why is this when a country has such potential, not just with its abundance of natural resources, but also human resources?
I was making a presentation the other week to an Indonesian oil company where I was asked what is delaying you getting projects in Indonesia, my answer was, “Do you really want to know”, he said yes, I mentioned several points which included acceptance of new technology, regulations, afraid to make decisions, other comments I cannot mention in the media, they returned my reply with agreement and also added a few other comments which were not complimentary to the regulators. It appears that Indonesian companies also have difficulties working in their own country.
Therefore, the question that has to be asked is: does Indonesia want to develop its own resources? We can see in some areas they do, such as wind and tidal power, solar power not so much, in other areas such as oil & gas it appears that the easy way is to import, which appeared to be the scenario given at the opening ceremony of the 41st IPA conference in May, hence the headline “Rising fuel imports stifle Pertamina”.
A recent study by The Habibie – Center said that the region lacks experience and expertise in capital-intensive renewable energy projects; maybe this is true, although you only gain experience by doing. Believe it or not, there are a lot of companies and people that want to help Indonesia, (not all for financial gain only), with the intent of doing business professionally and fairly, which also involves helping to solve the problem of expertise. All projects have to have local content, training must be given and allowed for in the cost of a project, not driving the price down so much that this area is reduced where the first thing that is cut when something goes wrong is training. Indonesia is extremely blessed with human resources, which in my experience, they are very efficient and in many cases can stand side-by-side with s other countries who claim to be experts at everything. So what is the problem, is it regulations?, partly yes, if we look at the intended Production Sharing Contract (PSC), it appears that very few investors and people in the industry are jumping over the moon about this, we all know that industries do not like change, but what is known, if the change is outstanding, the vast majority of industry leaders would accept this as a good idea, which makes one wonder if the PSC is a good idea in its current form, does it need more work on this to make it attractive?
The following statements were made by Pak Arie Rahmadi (BPPT), “Inconsistent regulations combined with long payback periods”; and “we change regulations on renewable energy quite often”. Why are regulations inconsistent and changed quite often? If they are good regulations, they only need fine tuning, not re-writing. Regulations should move with the times, we should not be making regulations for change sake, although this appears to be a worldwide problem with people in power at this time. If it is not broken, why fix it, preventive maintenance is needed only.
A headline in the Jakarta Post 25 July, “The President tells ministers to support business”, this article was prepared before this date. What the President stated is what is being stated in this article He also stated that the gross-spilt scheme lacks incentives, companies have said it does not have clear tax calculations.
Decision makers need to make decisions that are beneficial for the country and the investors, not be afraid to make decisions that may make them unpopular, after all, life is not a beauty contest.
*This article was first published by George Barber and is reprinted here with full permission from the writer.
**About the Writer:
George, Director at PT Indonesia, has lived and worked in South East - Indonesia for the past 24 years, and is presently involved with innovative exploration for natural resources throughout South East Asia.
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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