The International Energy Agency recently revealed that global investment in energy fell for a second consecutive year, by 12%, in 2016 across all energy types. The largest driver of that decline falls in the arena of fossil fuels – unsurprising, given the low price environment since 2015, dissuading any appetite for big budget spending. Instead, the world is moving towards clean energy investment – hitting 43% of total supply investment, a record high – while the energy sector is increasing focusing on power transmission and distribution, which exceeded spending on oil, gas and coal for the first time.
China, unsurprisingly, remains the largest energy investor. But it too is spending less on oil, gas and coal, and more on power and clean energy. It is also investing a lot on energy efficiency, now ranking only behind Europe in terms of percentage spent. Investment in the US saw a sharp drop – prices were too low for even nimble shale operators to thrive – while the report singles out India as the fastest-growing major market, as it plays catch-up with China in implementing necessary infrastructure to support a billion-plus people.
The drop in spending is, according to the IEA, worrisome. If the trend continues, depressed investment could lead to inadequate supply in the future – triggering another price boom, which will inevitably be followed by another bust, leading to another boom-bust cycle. It isn’t just oil and gas affected; although the share of investment rose, actual spending on global electricity only increased marginally in 2017 (to US$718 billion), while spending on renewable power fell by 3% (to US$297 billion). The shift in percentages largely because spending on upstream hydrocarbons and coal fell to only US$40 billion – half the annual spending for 2011-2015 and a third of the spending for 2006-2010. Only energy efficiency investment rose, to US$231 billion, contributed mainly by the large rise in China.
The outlook for the oil industry 2017 however is projected to be rosier if compared to 2016. With indications that crude prices are stabilising, range bound within US$45 – 55, investments into upstream are being revived selectively. The supermajors have all sanctioned multiple big budget projects this year – ExxonMobil has doubled it acreage in the Permian Basin earlier this year, BP is expanding its upstream spending notably in the US Gulf while Total signed off on the group’s first deepwater projects since 2014. The prospect of LNG in Africa is heating up, with groups like Eni capitalising. Meanwhile, the restructuring of the industry in Brazil following the Petrobras scandal could unlock acreage for foreign investment, finally fulfilling Brazil’s deepwater pre-salt potential. In the Middle East, Qatar wants to expand its natural gas and LNG production as a long-term security measure against touchy geopolitics, and Iran has every bit of ambition to reclaim its oil riches by drilling more.
In some cases, this mood has been offset by pullouts elsewhere – Chevron in Bangladesh and Thailand, ConocoPhillips along with others in Canada’s oil sands region – but the sort of pessimism that clouded the industry in 2016 has been slightly lifted.
In its place is a sort of cautious optimism that the future is brighter. This move to strategic investments than the wanton, mammoth projects of old seems to be the flavour of the day. Spend wisely and spend smartly, as they say. But as the industry refocuses on projects with shorter cycles, instead of projects taking multiple decades, there will be a need to pay important attention to the long-term adequacy of sustained energy supply, noting the recent warning from IEA. For now, at least, it seems like 2017 will be a better year for energy investment.
P.S. For continuity of investments in the energy industry, making the right choices is key for future success. Good templates for decision making processes exist that will allow arriving at such a choice in an orderly and structured manner. Although decisions can even be challenging in the context of limited uncertainty. Read more about “Uncertainty and the art of decision making” a recent blog post by Henk Krijnen.
Henk Krijnen will be in Kuala Lumpur this October 2017, presenting a very timely "Masterclass on Scenario Planning for Decision Making in the Energy Industry". Find out more https://goo.gl/tauq5x. If you are too busy during this period, check out our training series on “Training to Navigate Uncertainty in Oil & Gas”
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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