Last week, Indonesian state energy firm Pertamina admitted that the country may become a net importer of liquefied natural gas (LNG) by 2020, as soaring demand in the populous western islands dwarf domestic supplies from the energy-rich east. This isn’t the first time that this scenario has been mooted – the BMI Group projects the tipping point to be 2022, while Wood Mackenzie expects LNG demand in Indonesia to hit 7 mtpa by 2020 – with the fundamental structural shift always being the same: rising demand from a growing population and industrial base versus declining output at the country’s domestic gas fields.
As a country, Indonesia has some 1.6% of the world’s total gas reserves, according to the BP Statistical Review. In theory, it should not be in a situation where it is short of gas. The reality is though, that Indonesia is a country of two halves – the gas-deficit west, where the islands of Sumatra and Java represent nearly three-quarters of demand, and the gas-surplus east, where remote areas in Kalimantan, Papua, Maluku and Nusa Tenggara churn out plenty of natural gas. Bridging the two is tough. As an archipelago, Indonesia cannot opt for a nation-wide pipeline network; even within the country, domestic liquefaction and regasification facilities are required to move natural gas from producing areas in the east to consuming areas in the west.
That infrastructure is still lacking. Indonesia has a national roadmap to make natural gas 20% of the national energy mix by 2025, and has set out a US$48.2 billion plan from 2016 to 2030 to build an ambitious gas grid. The existing infrastructure is mainly concentrated on regas facilities in Java and a pipeline connecting to Riau islands in the South China Sea to Java running through Sumatra, which does not solve the conundrum of moving gas from Indonesia’s east to west. So the planned investment will be primarily focused on building a network of smaller-scale liquefaction facilities across the east, supplemented by mini-LNG terminals connected directly to gas-fired power plants in the east.
This, in theory, should allow Indonesia to bridge the gap between its two halves. The question is, will there be enough gas? Indonesia is currently the fifth largest LNG exporter in the world, but its contracts are aging and based on maturing fields where international firms are the operators. They will be sending most of that LNG to Japan and Korea, with a lesser portion saved for the Domestic Market Obligation (DMO) clause. Given declining natural gas output in recent years, the DMO supply is insufficient to meet growing demand. Unlike Petronas in Malaysia, Pertamina does not have an international network of gas and LNG sources with which it can swap and juggle to maintain domestic balance.
Starting up new production sources is an answer, but this has always been an area that Indonesia faces immense problems with due to the fiscal terms it offers for its E&P contracts. ExxonMobil walked away from the East Natuna project earlier this year over exactly that, while years of wrangling have push the projected start of Inpex/Shell’s Masela-Abadi LNG project from 2018 to 2025 at the earliest. Chevron’s Indonesia Deepwater Development (IDD) project in the Makassar Strait was supposed to start in 2016, but has now been pushed to 2020 due to ‘bureaucratic holdups’. These three, and other projects, would have provided enough additional LNG supplies to allow domestic supply to keep pace with demand, but chronic delays have axed the scenario. That isn’t to say that there aren’t bright spots in Indonesia’s natural gas scene – Eni’s Jangkrik field is reporting results that are a third higher than its initial 450 mmscf/d capacity, and BP has sanctioned an expansion of Tangguh LNG to include a Train 3 – but these are balanced with weak spots, like Total’s recent reduction in the expected output for the Mahakam field, which feeds the Bontang LNG plant.
So Indonesia must turn to imports to meet demand, which is projected to grow rapidly given the Indonesia government’s push to move power generation from coal to gas. A recent suggestion that Indonesia may be purchasing LNG from Singapore caused some furore based on national pride last month, but this is the future. Pertamina already has LNG supply deals with Australia’s Woodside (2019-2034), Cheniere (from 2018-2038) and ExxonMobil (2025-2045). Cavalier Indonesian officials may think that this might not even be needed – suggesting that this is ‘insurance’ supply that can be quickly redirected on the international market – but reality is more stark. As things stand, if there was an OPEC for gas, Indonesia would be forced to bow out in 2020. That’s not necessarily a bad thing – Malaysia recently went through a similar evolution – but it does mean that resource patriotism can no longer apply.
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Headline crude prices for the week beginning 7 January 2019 – Brent: US$57/b; WTI: US$49/b
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At some point in 2019, crude production in Venezuela will dip below the 1 mmb/d level. It might already have occurred; estimated output was 1.15 mmb/d in November and the country’s downward trajectory for 2018 would put December numbers at about 1.06 mmb/d. Financial sanctions imposed on the country by the US, coupled with years of fiscal mismanagement have triggered an economic and humanitarian meltdown, where inflation has at times hit 1,400,000% and forced an abandonment of the ‘old’ bolivar for a ‘new bolivar’. PDVSA – once an oil industry crown jewel – has been hammered, from its cargoes being seized by ConocoPhillips for debts owed to the loss of the Curacao refinery and its prized Citgo refineries in the US.
The year 2019 will not see a repair of this chronic issue. Crude production in Venezuela will continue to slide. Once Latin America’s largest oil exporter – with peak production of 3.3 mmb/d and exports of 2.3 mmb/d in 1999 – it has now been eclipsed by Brazil and eventually tiny Guyana, where ExxonMobil has made massive discoveries. Even more pain is on the way, as the Trump administration prepares new sanctions as Nicolas Maduro begins his second term after a widely-derided election. But what is pain for Venezuela is gain for OPEC; the slack that its declining volumes provides makes it easier to maintain aggregate supply levels aimed at shoring up global oil prices.
It isn’t that Venezuela doesn’t want to increase – or at least maintain its production levels. It is that PDVSA isn’t capable of doing so alone, and has lost many deep-pocketed international ‘friends’ that were once instrumental to its success. The nationalisation of the oil industry in 2007 alienated supermajors like Chevron, Total and BP, and led to ConocoPhillips and ExxonMobil suing the Venezuelan government. Arbitration in 2014 saw that amount reduced, but even that has not been paid; ConocoPhillips took the extraordinary step of seizing PDVSA cargoes at sea and its Caribbean assets in lieu of the US$2 billion arbitration award. Burnt by the legacies of Hugo Chavez and now Nicolas Maduro, these majors won’t be coming back – forcing Venezuela to turn to second-tier companies and foreign aid to extract more volumes. Last week, Venezuela signed an agreement with the newly-formed US-based Erepla Services to boost production at the Tia Juana, Rosa Mediano and Ayacucho 5 fields. In return, Erepla will receive half the oil produced – generous terms that still weren’t enough to entice service giants like Schlumberger and Halliburton.
Venezuela is also tapping into Russian, Chinese and Indian aid to boost output, essentially selling off key assets for necessary cash and expertise. This could be a temporary band-aid, but nothing more. Most of Venezuela’s oil reserves come from the extra-heavy reserves in the Orinoco Belt, where an estimated 1.2 trillion barrels lies. Extracting this will be extremely expensive and possibly commercially uneconomical – given the refining industry’s move away from heavy grades to middle distillates. There are also very few refineries in the world that can process such heavy crude, and Venezuela is in no position to make additional demands from them. In a world where PDVSA has fewer and fewer friends, recovery will be extremely tough and extremely far-off.
Infographic: Venezuelan crude production:
Headline crude prices for the week beginning 31 December 2018 – Brent: US$54/b; WTI: US$46/b
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