While oil is still suffering the effects of oversupply, another supply bubble is growing – gas. Or more specifically, LNG. It is a problem the entire industry can see coming, and is already flipping power from the industry’ sellers to buyers.
What’s the appeal in LNG? Natural gas requires extensive pipeline infrastructure to pipe from source to consumption, so travelling long distances – say from Australia to Japan - is untenable. However, that natural gas can be supercooled into liquid form, then placed on a LNG tanker to be shipped across the world. It opened up natural gas to markets that wouldn’t otherwise have access to it, diversifying energy mixes and being a cleaner-burning fuel as well. It was this that got Japan started on LNG in the 1990s, an addiction that has spread across Asia. So hungry was Asia for the fuel, that it created a sellers market where buyers were locked in 15-, 20- and longer contracts at high prices, because, where else would they get their LNG from?
This expectation of captive damage fuelled the LNG boom over the last decade, triggering a race for Asia. Australia, with its vast gas reserves in Western Australia, was closest. Canada’s gas reserves in British Columbia were also well-positioned to serve Asia. The Middle East, in particular Qatar, also got in on the game, along with Asian sources like Indonesia and Papua New Guinea. The US would have joined, but the shipping lane – which required circling around Tierra del Fuego at the southern tip of the continent – incurred too much shipping costs, so it focused on the Atlantic Basin. The prize was long-term contracts with the Japanese and Koreans at high fixed prices, and a plethora of profits.
Herd mentalities create bubbles, and as more and more players joined the fray with more and more gas discoveries – Africa and recently, Israel, are some of the new players – it was always assumed that Asia would be ready to absorb it. It is not. The market is already in a glut, and Wood Mackenzie predicts that the oversupply will peak at 60 million tons per annum in 2019, based on current operational and announced projects. Yet more projects are still being announced. And the widening of the Panama Canal now brings US LNG to Asia too.
It’s a situation eerily similar to the oil market. Except in oil, there is OPEC and as diminished as its powers are today, it still wields significant clout that a statement by OPEC to curb output can send oil prices rallying. The Gas Exporting Countries Forum (GECF) has nowhere near such influence or power, nor do they have a swing producer equivalent of oil’s Saudi Arabia. And as with oil, much of the new LNG export capacity – up to 100 mtpa under construction in the US and Australia alone – is in private hands, not subject nor interested in an oligopoly.
So the glut continues and buyers are spoilt for choice. Japan and India are already moving to renegotiate the strict contracts that left them locked into supplies that they may not need and cannot resell. Japan, indeed, predicts that it will have enough excess LNG coming into its system to establish an LNG trading hub, an ambition echoed by Singapore and South Korea, which will add more transparency to the market to the detriment of sellers.
A crash is waiting to happen in the LNG market. There is far too much supply and even as the supply glut forces prices down, there is still too much to be absorbed, not only in Asia but the rest of the world. And when it happens, it will impact not only the gas producers, but shippers and construction firms as well. It is a good time to be a buyer; as a seller, it is time to consolidate, be cash-rich not debt-heavy and prepare for a rough future. The current crisis in oil is a glimpse of a future that LNG-linked players need to prepare for.
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
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