Last week in the world oil:
-Although trading is thin ahead of Christmas, oil prices have maintained their gains last week, opening the week at the US$52/b levels, as the market anticipate tighter supplies next year, which should end the year on a positive note after a prolonged weakness in prices.
Upstream & Midstream
-The UAE, Kuwait and Oman have joined Saudi Arabia is implementing the planned OPEC cuts, warning some clients on long-term contracts that they would receive reduced supplies of crude from January. Saudi Aramco is also telling a few Asian clients that the cuts would impact them as well.
-Libya’s Sharara and El Feel oil field pipelines have been re-opened, after protestors blocking the assets agreed to halt their action. The oil guards have restarted the long blockaded pipeline, which could restore up to 400 kb/d of output to Libya’s production. Libya’s crude output is one of the two (Nigeria is the other) exempt from the new OPEC supply quotas.
-While other companies are restarted their oil sands projects, Norway’s Statoil is planning a complete exit. It has agreed to sell its Leismer and Corner sites, along with associated midstream assets, to Canada’s Athabasca Oil for C$832 million, which would leave Statoil with no oil sands assets, figuring that the segment will be remain too challenging.
-The US rig count jumped again last week, up by 13, with 12 of those being oil rigs as US producer dilute the OPEC deal by ramping up production.
-Shell will likely sell its 38.5% stake in the 220 kb/d Schwedt refinery in Germany to Varo Energy (a joint venture between Vitol and the private equity Carlyle Group). This deal is part of Shell’s drive to dispose of US$30 billion in assets to pay for its acquisition of the BG Group.
-Petrobras will sell its minority 49% stake in sugar/ethanol company Nova Fronteira Bioenergia to its existing joint venture partner São Martinho for US$133 million in a shares-only payment. The move would hasten Petrobras’ exit from domestic biofuels, but it has indicated that it plans a re-entry once it completes its debt reduction plans. In other Petrobras news, the company has signed a US$5 billion, 10-year financing deal with China Development Bank Corp, as well as agreeing an oil supply accord with China National United Oil, China Zhenhua Oil and Chemchina Petrochemical as its seeks a secure stream of revenue and funding.
Natural Gas & LNG
-Italy’s Eni has sold a 30% stake in its giant Egyptian offshore Zohr gas field to Russia’s Rosneft for US$1.575 billion, after selling a 10% to BP for the same price. Zohr is the largest natural gas find in the Mediterranean thus far, and while Eni is typically good at discovering fields, it lacks the financial clout to pursue its discoveries on its own.
-With CEO Tex Tillerson heading into the US government as Donald Trump’s Secretary of State, ExxonMobil has named heir apparent Darren Woods as the company’s next chairman and CEO. The boss of ExxonMobil’s refining arm since 2012, Woods’ challenge will be to bring his ability to whip refineries into shape to the company’s larger portfolio, including its challenged upstream business.
Last week in Asian oil:
Upstream & Midstream
-Malaysia’s Petronas is finalising the next round of its PanMalaysia transportation and installation contract, which should provide a boon to offshore contractors hurting for business in Asia. The contracts awarded by Petronas cover domestic upstream oil and gas T&I activities for three years, with the previous round in 2014. The bulk of the contracts this time are said to be in the state of Sarawak, as Petronas aims to bulk up its deepwater activities in East Malaysia.
Downstream & Shipping
-China has dealt a blow to its teapot refineries, refusing to renew their fuel export quotas for 2017. This means that any fuel produced by the independent refiners have to be sold within China. This would transform assumptions of the Chinese oil market in 2017, as the teapots were expected to import sizeable amounts of crude. But with outlets now limited to the domestic market and consumption slowing down, this move upends that and we very well see teapot production decline. On the plus side, it may remove the glut of refined products sloshing around Asia, allowing cracks and prices to rise.
-CNOOC’s 200 kb/d Huizhou refinery will start up in May or June 2017, with Saudi Arabia named at the mainly supplier for the plant. CNOOC has traditionally been a more offshore upstream player, but has moved downstream as the traditional lines delineating China’s Big Three energy groups have blurred.
-Indonesia has officially assigned Pertamina to build and operate a planned refinery at Bontang in East Kalimantan. The 300 kb/d project always had to involve Pertamina – it is the state energy company, after all – but this does not mean the project will see fruition; Pertamina does not have the means to undertake a refinery project this big on its own and has faced considerable problems in moving ahead with joint venture partners. Indonesia will also import 500,000 tons of LPG from Iran next year, aimed at plugging a domestic shortage.
-Shell continues its withdrawal from what it considerable peripheral downstream markets, selling its aviation fuel business in Australia to Viva Energy for US$250 million.
Gas & LNG
-Russia’s Novatek, its second biggest gas producer, has signed individual agreements with Japan’s Mitsui, Mitsubishi and Marubeni for co-operation in LNG and energy. The deals will see the companies co-operate in upstream natural gas projects in Russia, including the Arctic LNG-2 project, with Japan hungry to secure LNG supplies while Russia wants to boost its global LNG market share.
-Qatar will merge its two state-owned LNG producers, consolidating Qatargas and RasGas under QatarGas. The move is a reaction to the prolonged slump in oil prices, which has affected LNG given its oil-linked pricing, cutting costs in the town state-run behemoths. Qatargas and RasGas were originally created as separate companies to focus on the Eastern and Western markets, as well as to encourage competition
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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