Easwaran Kanason

Co - founder of PetroEdge
Last Updated: November 6, 2017
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Business Trends
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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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Your Weekly Update: 7 - 11 January 2019

Market Watch

Headline crude prices for the week beginning 7 January 2019 – Brent: US$57/b; WTI: US$49/b

  • Crude oil looks set to climb back to previous support levels as OPEC’s new supply deal kicks in and the US Federal Reserve sought to soothe investor confidence after initiating a surprise hike in interest rates that caused widespread global financial panic in December
  • Even as OPEC+ moves forwards with a planned 1.2 mmb/d cut in collective output, production across OPEC had already fallen over November and December as Saudi Arabia throttled production to support falling prices
  • Together with dwindling production in Venezuela, disruptions in Libya and losses in Iran, oil output from OPEC countries has already fallen by 530,000 b/d in December to 32.6 mmb/d, the sharpest pullback since January 2017
  • This has managed to re-assure the market that the global supply/demand balance is on firmer footing, even as Russian oil output reached a post-Soviet high of 11.16 mmb/d, just slightly off the all-time record of 11.42 mmb/d in 1987
  • With the recovery in prices, planned upstream projects will be back on firmer footing, with Rystad Energy expecting some US$123 billion of offshore projects to be sanctioned over 2019 if Brent crude averages US$60/b
  • Also supporting the upward momentum is the removal of 8 oil rigs from the active US rig count, as American drillers weighed up the risks of the fragile trajectory in WTI prices
  • Crude price outlook: Momentum is with crude oil prices this week, and we expect that to continue as OPEC+ implements its production plan, with Brent recovering to US$60-62/b and WTI to US$51-53/b


Headlines of the week

Upstream

  • Eni has acquired the remaining 70% of the Oooguruk field in Alaska from Caelus Natural Resources, bringing its stake to 100% to synergise with the nearby Nikaitchuq field, where Eni also owns a 100% interest interest
  • The deepwater Egina field in Nigeria, operated by Total through an FPSO, has started up production, with peak output expected at 200,000 b/d
  • Commercial production of crude at PAO Novatek/Gazprom’s Yaro-Yakhinskoye field has commenced, with output expected at 24,000 b/d
  • Total has sold a 2% interest in Oman’s Block 53 to Sweden’s Tethys Oil, bringing it into Occidental Petroleum’s 100,000 b/d Mukhaizna field
  • Brazil is preparing for its sixth round of upstream auctions, offering up pre-salt acreage in five areas expected to raise more than US$2 billion in sales
  • After recently making its 10th discovery in Guyana, ExxonMobil has its sights set on more as it drills two more exploration wells – Haimara-1 and Tilapia-1 – in the prolific Stabroek block, both close to existing discoveries
  • Ecuador is initiating a probe into some US$4.9 billion worth of oil-related infrastructure projects initiated by the previous administration on charges of corruption and looting

Downstream

  • China appears to be tempering crude demand, with the first batch of crude oil import quotas issued to state and private refineries at 26% lower than 2018, with quotas for teapots at some 78% of the 89.84 million tons approved
  • Saudi Aramco has acquired complete ownership of German specialty chemicals producers Lanxess AG by acquisition Dutch firm Arlanxeo’s 50% stake at €1.5 billion, strengthening its foray into petrochemicals
  • Iran will be investing some US$212 million into Chennai Petroleum’s 180 kb/d expansion of the Nagapatinam refinery on India’s east coast, as Iran looks for ways to ensure captive demand for its crude in one of its largest markets
  • The Mariner East 2 NGLs pipeline – transporting ethane, propane and butane over 560km to the Marcus Hook processing plant in Pennsylvania – has been completed, with the Mariner East 2X pipeline schedules for late 2019

Natural Gas/LNG

  • Shell’s 3.6 mtpa Prelude FLNG has finally started up initial production, the last of Australia’s giant natural gas projects to be completed
  • Brunei Shell Petroleum (BSP) has completed the onshore Darat Gas Project in Lumut, expanding LNG capacity in Brunei by 5% at the Rasau station
  • ExxonMobil’s Rovuma LNG project in Mozambique will be aiming to sanction FID in 2019 for its first phase, involving two trains with a combined capacity of 7.6 million tpa from the offshore Area 4 block
  • As LNG developments in Papua New Guinea move quickly to commercialisation, the PNG government has passed new laws to impose a domestic gas requirement and other provisions for new gas projects, to ensure adequate supply of resources for growing local demand
January, 11 2019
The Prospects of Venezuelan Oil

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:

  • 2015: 2.7 mmb/d (output), 1.9 mmb/d (exports)
  • 2016: 2.6 mmb/d (output), 1.8 mmb/d (exports)
  • 2017: 2.1 mmb/d (output), 1.5 mmb/d (exports)
  • 2018: 1.3 mmb/d (output), 1.2 mmb/d (exports)
  • November 2018: 1.15 mmb/d (output), 1.05 mmb/d (exports)
January, 10 2019
Your Weekly Update: 31 December 2018 - 4 January 2019

Market Watch

Headline crude prices for the week beginning 31 December 2018 – Brent: US$54/b; WTI: US$46/b

  • Crude oil will start 2019 on a stronger note after being routed last month over concerns that surging American production will swamp OPEC’s supply efforts and a global financial panic triggered by US trade policies and tighter monetary policy by the Federal Reserve
  • OPEC is continuing to re-iterate that it will play a strong role in managing global oil supply and demand, but there are worries that it may have to switch tactics to deal with the non-stop rise in US shale volumes
  • Concerns over the health of the global economy are also on the minds of traders, with signs that the Chinese economy is slowing down as the country’s manufacturing index has begun to contract
  • Suppression of demand growth could cap the ability for crude oil to rise up to the predicted average of US$70/b for the year, making supply management all the more important with Saudi Arabia pledging ‘deeper cuts’
  • American drillers added 3 new rigs in total heading into the new year, underscoring the continuous upward trajectory for US oil production – with signs pointing to the 12 mmb/d mark likely to be hit by mid-2019
  • Crude price outlook: The market should stabilise itself at US$54-55/b for Brent and US$46-47/b for WTI, with traders watching for signs over the implementation of OPEC+’s new supply deal

 

Headlines of the week

Upstream

  • BP is aiming to sanction development of the Platina field in Angola’s deepwater Block 18 in 1H2019, which would be the supermajor’s first new development in the country since 2013, following an extension of Greater Plutonio to 2032
  • Shell has completed the sale of its New Zealand upstream assets – including the Māui, Pohokura and Tank Farm entities – to Austria’s OMV for US$578 million
  • Eni UK has begun drilling in Rowallan well in the Central North Sea with Serica Energy, targeting condensate-rich volumes in well 22/19c-G
  • In South Africa, Total has begun drilling the Brulpadda-1AX well in offshore Block 11B/12B, with prospective resources of 500 million barrels of crude
  • Equinor has completed the sale of two assets on the Norwegian Continental Shelf, selling a 77.8% stake in King Lear to Aker BP for US$250 million as well as a 42.38% stake in Tommeliten Unit and 30% in PL044 to Poland’s PGNiG for US$220 million
  • Commercial crude production at the SARB and Umm Lulu fields in Abu Dhabi has begun, with Cepsa offering first crude from the sites last month

Downstream

  • Saudi Aramco has established the Saudi Aramco Retail Company (RetailCo), a new subsidiary focus on fuel retailing in the Kingdom as part of its plan to expand its business further downstream
  • After starting up official commercial production last month, Vietnam’s Nghi Son refinery has offered up its first cargo of jet fuel, joining the site’s existing slate of gasoline and gasoil volumes
  • BP and SOCAR have signed an agreement for a new petrochemicals joint venture in Turkey, with the proposed site in Aliaga aiming to have a capacity of 1.25 mtpa of PTA, 840,000 tpa of paraxylene and 340,000 tpa of benzene
  • Total and Angola’s Sonangol are extending their partnership downstream, forming a joint venture to focus on fuel and lubricants distribution and sales in Angola, as well as developing a new fuel retail network

Natural Gas/LNG

  • Australia’s Woodside Petroleum has inked a new mid-term deal with German utility RWE supplying LNG from the Corpus Christi LNG project in Texas from 4Q2020 to 4Q2022 – an extension of the 12 cargo, 2-year contract signed between both parties last year
  • Gazprom and Itochu have signed an MoU to cooperate on the proposed Baltic LNG export project, a 10 mtpa liquefaction plant planned in Leningrad
  • Eni has received permission from the Indonesian government to fast-track the Merakes Development Project in Kalimantan’s Kutei Basin, aimed at delivering additional volumes to the Bontang LNG plant
  • Indonesia is reviewing Inpex’s revised development plan for the Abadi LNG project as the Japanese firm has reportedly identified a small island in South Tanimbar as the location for the plant
January, 03 2019