Last Week in World Oil:
- Oil prices inched up at the start of the week, buoyed by the effective implementation of the OPEC producer cuts. However, the rising prices have also encouraged rising production in the US, keeping gains in check along with stubbornly high US stockpile levels.
- The Brent crude benchmark, which forms the bulk of global oil trade, is being overhauled for the first time in a decade to account for declining production in the North Sea. Effective immediately, pricing agency Platts has added the Norwegian Troll crude grade to the basket of four British and one Norwegian crudes (Brent, Forties, Oseberg and Ekofisk) that form Brent to expand the physical volume of crude underpinning the benchmark, making it less vulnerable to manipulation.
Upstream & Midstream
- TransCanada has re-filed an application with Nebraska to route the proposed Keystone XL pipeline through the state. The original application was withdrawn after President Obama vetoed the pipeline project, but with a friendlier administration in the White House, this brings Keystone XL one step closer to implementation and operational reality.
- Iraq and Iran have agreed to explore the possibility of a pipeline linking the two nations, expanding export options for Kirkuk crude in northern Iraq as well as provide crude for the Abadan refinery in Iran. Currently Kirkuk crude is transported through Kurdish territory, complicating matters as the Kurds have interrupted Kirkuk transit in the past.
- Thirteen new onshore oil and gas rigs were added to the US rig count last week, offsetting a loss of three offshore rigs to bring the total active rig count up to 751. It is the fifth consecutive week of rises, leading to the EIA forecasting a rise in domestic oil output to 4.87 mbpd in March, which would be the fastest rise since October, underpinned by shale oil plays.
- The Ras Laffan Refinery 2, which began production in late 2016, will be geared towards producing aviation fuel, with a dedicated pipeline connecting it to the Doha International Airport expected to be completed in 2018. Ras Laffan 2 runs on condensate, with a capacity of 146 kb/d, and will also produce naphtha for petrochemical processing and ultra low-sulphur diesel for export to Europe.
Natural Gas and LNG
- Petronas and the government of British Columbia are offering an additional C$145 million to two First Nation groups that would allow a US$27 billion LNG project to go ahead. Federal approval for the project was given last September for the Pacific Northwest LNG, but additional amendments are proposed to quell environmental and native group opposition to the project. Politics is now also in the fray, with the opposition candidate for the BC premiership opposing the current site of the planned facility, with elections due in May 2017.
Last Week in Asian oil:
Upstream & Midstream
- Petronas may be selling a large minority stake in a prized upstream gas asset in Sarawak, to raise cash and cut development costs as the Malaysian state player seeks to improve its financials. Petronas will retain a majority stake in the SK316 offshore gas block, but up to 49% of the asset may be sold off. The block is currently home to the NC3 field, which feeds the LNG9 joint venture export project with JX Nippon, as well as the Kasawari field. Likely buyers would be Japanese and Korean gas importers.
- Chevron has secured an offshore permit in Western Australia for AUS$3 million, the first cash bid permit to be awarded since 2014. The cash bid permit was reintroduced to drive interest‘in mature areas or areas known to contain petroleum accumulations’, essentially a cost-effective way of driving interest in areas that have a high percentage of recoverable resources. The WA-526-P permit is in a gas-rich area of the Northern Carnarvon basin close to the Gorgon and Pluto LNG projects, and is the first success of a series of disappointing cash bid auction results.
Downstream & Shipping
- Thailand’s largest oil refiner ThaiOil set out its operational plans for 2017 last week, aiming to runs its 275 kb/d refinery at within 100-103% capacity with no major maintenance shutdowns planned. Productivity rates exceeding 100% are common in Thailand where official refinery capacity is underestimated, with the Sriracha refinery reaching rates of 108% last year, almost all of which was consumed domestically.
Natural Gas & LNG
- More LNG will be entering Singapore as natural gas contracts supplied via pipeline from Malaysia and Indonesia near expiration. To mitigate this, Shell and Pavilion Gas will deliver their first LNG cargoes to Singapore later this year, under contracts awarded in October 2016 for three years or a maximum of 1 million tons per year. Singapore will also be allowing for up to 10% of imports coming from the spot market, to even out supply and bolster its ambitions of becoming the LNG trading hub for Asia
- Weak LPG prices are boosting demand in South Korea. Traditionally used as a transport fuel, LPG consumption in South Korea has declined significantly since 2010 as vehicles switched to gasoline and diesel, leaving major importers SK Gas and E1 scrambling for new customers. With a glut in natural gas liquids leading to low prices and a recovery in consumer plastics strengthening Asian petrochemical margins, LPG demand has jumped, benefitting American exporters. In 2016, South Korea’s LPG demand rose to 9.4 million tons while imports jumped to 7 million tons, more than half of which was supplied by US Gulf exporters. LPG usage in petrochemicals more than doubled to 3.3 million tons.
- The Elk-Antelope LNG project in Papua New Guinea is now targeted at the end of 2018, a delay from its original date of late 2017. One of the largest undeveloped gas assets in Asia, the Elk and Antelope fields are operated by Total, partnering with InterOil on the LNG export project. The ExxonMobil acquisition of InterOil would have streamlined the natural gas scene in PNG, but some ownership quibbles have delayed the acquisition until the Supreme Court of Yukon confirmed that the sale could go ahead on Sunday.
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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