LONDON (Reuters) - Having turned round its North American shale business, Royal Dutch Shell is putting so-called unconventional energy at the heart of its growth plans, and believes lessons from the revamp can be applied across the company.
Greg Guidry, head of the Anglo-Dutch group's unconventionals business, told Reuters a drive to slash costs and streamline decision-making had put his division largely on a par with leading rivals in terms of productivity and efficiency.
And now the rest of Shell could reap the benefits too.
"The executive committee charged us to be a catalyst for change within the broader Shell," Guidry said in an interview.
He also said Shell planned to make small acquisitions near its existing North American shale areas, notably from producers struggling in the current industry downturn, and hoped to launch an early production well this year in Argentina's Vaca Muerta, considered the world's No.2 shale resource after North America.
That's quite a change in fortunes.
As recently as late last year, Shell Chief Executive Ben van Beurden was considering jettisoning the unconventionals business over concerns it would drag down group profitability after the group's $54 billion acquisition of BG Group in February.
Shell and rivals including Chevron and Exxon Mobil were late to the shale revolution at the end of the last decade and struggled to match the success of smaller independent producers that increased U.S. output by around 4 million barrels per day between 2008 and 2015.
Oil majors' often cautious pace in complex, high-risk projects was ill-suited to the nimble needs of shale, which requires drilling hundreds of wells and injecting water at high pressure to break the rock that holds oil and gas.
So Shell moved to adapt.
In recent years, it has shed half of its North American unconventional assets for around $4 billion to focus on four areas in the United States and Canada.
It has cut its technical check-list for drilling shale wells from 20,000 requirements to less than 200 and given managers "end-to-end" control of the production process from well exploration through to well abandonment, Guidry said.
The division's efficiency has risen by 50 percent over the past three years, production has grown by 35 percent and capital spending is down by 60 percent to around $2.0-$2.5 billion.
Today, Shell makes a profit from shale oil production in "sweet spots" in the Permian or Duvernay in Canada with crude prices of $40 a barrel, Guidry said. After dipping below $30 in January, Brent crude is currently trading around $48.
"In terms of execution, we are completely competitive and have aspirations to be leading," Guidry said, adding the business could now compete with leading shale producers such as Pioneer Natural Resources and EOG Resources though costs still could be reduced.
Advances in technology meant there was scope to increase oil recovery from shale rock from today's 7-9 percent by another 1-3 percent over the coming years, Guidry added.
"That is billions of barrels. We absolutely can reach that," the 55-year-old American said.
And unlike multi-billion deepwater projects, shale can be turned on "with the drop of a hat," Guidry said.
At around 300,000 barrels per day, shale today represents around 8 percent of Shell's overall production. However, Shell holds shale reserves of around 12 billion barrels, roughly as much as its deepwater resources, Guidry said.
The shale business got its reward earlier this month when Van Beurden identified it as a key growth priority for Shell in the next decade along with renewable energy.
What's more, Shell engineers are now using the experience in the shale business to improve deepwater projects, which helped knock out $1.5 billion in costs for the development of the Stones field in the Gulf of Mexico.
As oil producers scrap costly and complex projects such as deepwater fields and sharply reduce budgets in the face of the oil price downturn, they are turning again to onshore shale which offers quicker returns and lower investments.
Some analysts, including at Bernstein, still argue Shell should divest the shale business to focus on core strengths such as deepwater and liquefied natural gas (LNG), which are generating larger profits.
"Surely private equity would have offered some healthy cash proceeds for this business today," said Bernstein analyst Oswald Clint, who rates Shell shares "outperform".
But analysts at U.S. investment bank Tudor Pickering, Halt and Co. see growing value in Shell's unconventional portfolio, particularly in the Permian basin, which they value at $13 billion if oil hits $75 a barrel.
"We believe Shell's North American unconventional portfolio is less core relative to global deepwater and LNG but we do see additional value that should command a premium multiple when compared to its European supermajor peers," they said.
By Ron Bousso
(Editing by Mark Potter)
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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