Strategically-worded statements from OPEC, in particular signals from Saudi Arabia that it was moving to stabilise markets, lifted oil prices last week, moving up to the mid-US$40s as traders bet that the OPEC talks will lead to a balancing of supply with demand.
Russia’s Rosneft announced that it had made a new condensate find at its Wild Orchid gas field in Vietnam, located in the prodigious Nam Con Son offshore basin. Pre-drill preliminary assessments indicate 12.6 billion cubic metres of gas and 5.4 million barrels of condensate, which ties in synergistically as it can be linked to Rosneft Vietnam’s existing Lan Tay production platform.
Australia launched the 2016 Offshore Petroleum Exploration Acreage Release last week, covering 28 areas across five basins. The offshore blocks on offer are in the Bonaparte Basin, Browse Basin, Offshore Canning Basin, Roebuck Basin and Northern Carnarvon Basin in Western Australia, with 25 areas up for work program bidding and three areas for cash bidding.
CNPC has begun work on the fourth Shaanxi-Beijing gas pipeline, moving 25 billion cubic metres of gas per annum to China’s energy-hungry capital in a bid to reduce smog from oil- and coal-burning power plants. There are already three existing pipelines with total capacity of 35 billion cubic metres, and the new 1,114 km pipeline will bring that total up to 60 billion cubic metres when it starts up in October 2017.
Indian oil demand is growing fast, outpacing even China’s growth currently, and refiners are planning ahead to feed that demand. CPCL (Chennai Petroleum) has announced a US$3 billion plan to expand its Nagapattinam plant in Tamil Nadu from 20 kb/d to as much as 180 kb/d. A feasibility study is underway and the plans, if finalised, will go to approval by the Ministry of Petroleum and Natural Gas next year.
In more Indian refinery news, the Numaligarh Refinery in Assam, a joint venture owned by BPCL and Oil India, is planning a US$3 billion expansion of its 80 kb/d refinery, which would treble the site’s capacity to 180 kb/d. Surging demand in India’s northeast is the impetus behind the plans. Ministry approval is required for the plan to go ahead.
Santos is setting aside A$1.05 billion to pay for a tax impairment charge on its Gladstone LNG project in its 1H16 financials. The impairment comes dues to a slower ramp up of Gladstone equity gas production and an increase in third-party gas prices, with sustained low oil prices constraining capital expenditure and Gladstone ramp-up.
Indonesia has approved plans to create holding companies for state firms, including those in the energy sector. Under the new framework, which is designed to encourage state-owned companies to spearhead industrial development, PT Pertamina will be the holding company of the oil and gas sector, with PGN (Perusahaan Gas Negara) as one of its units. This will hopefully bestow some measure of decisive power in Pertamina, which it can use to push ahead with some of its ambitious upstream and refinery projects to increase Indonesia’s crude production and reduce its current dependence on imported oil products.
Continued attacks on pipeline infrastructure in Nigeria persist, despite the government issuing cash payments in efforts to negotiate peace talks. Last week, Shell declared force majeure for Bonny Light crude liftings when a leak appearing on the Niger Delta pipeline. Bonny Light is Nigeria’s fourth crude stream to be under force majeure for deliveries, after Qua Iboe, Forcados and Brass River. ExxonMobil, which exports Qua Iboe, is attempted to re-route its streams via an alternate pipeline while it focusing on repairing the main line damaged in July.
With its energy policy now set in stone, Israel is preparing to exploit the country’s new discoveries of gas (and oil). With regulatory uncertainties now eliminated, some 24 offshore exploration blocks will be up for tender in November, all of which are close to the Leviathan gas field. Preliminary indications by the Israeli Energy Ministry indicates 2,200 billion cubic metres of natural gas and 6.6 billion barrels of oil set to be discovered in Israeli waters, according to a geological survey.
Israel’s neighbor to the south, Egypt, has approved five oil and gas E&P agreements with foreign companies. BP, ENI, Total and Edison will partner with Egypt’s state gas board EGAS on four fields in the Mediterranean, while Trident Petroleum joins EGPC in the Red Sea.
Some 15 new oil rigs started up in the US last week, bringing the total number of operating oil rigs to 396, as onshore producers took heed of OPEC’s signals to strengthen prices. Gas rigs rose by 2, bringing the total number of rigs up to 481, the highest number since March 2016.
A fire broke out at the Motiva refinery in Convent, Louisiana last week. The fire was put out within the day, but not before heavily damaging the structure of the site’s heavy oil hydrocracker. The 235 kb/d is expected to be partially shut down for at least a month to repair the damage to the 45 kb/d heavy oil unit. The wider refinery will remain operational.
Expansions at the Sohar refinery in Oman are now expected to come onstream by early 2017, a slight delay from the original end-2016 start date, which would increase refining capacity to some 90 kb/d. Crude processed will be domestic, reducing the country’s crude exports by at least 50 kb/d when Sohar’s new units start up.
South Korea’s Kogas has signed an MoU with the government of Yucatan state in Mexico to build an LNG import terminal and associated pipeline infrastructure. The proposed site for the project is Progreso, well-placed to receive shipments of LNG coming from the US on the other side of the Gulf of Mexico.
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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