LONDON (Reuters) - A British vote to leave the European Union next week would make UK energy infrastructure investment costlier and delay new projects at a time when the country needs to plug a looming electricity supply gap.
Energy has been far from central to debates about whether to leave the EU - a move dubbed "Brexit" - but the sector would still be impacted by a decision in the June 23 referendum to quit the 28-nation bloc.
After a Brexit vote, all EU laws apply in Britain until two years after London starts the process to leave. Then none would apply but Britain could try to stay part of some frameworks through negotiations, a process that could take years.
Uncertainty about the type of relationship Britain would have with the EU after Brexit would make energy investors demand higher returns for the risk of less favourable conditions.
Oil and gas majors BP and Shell are among several energy companies that say leaving the EU would affect them and the sector negatively.
"I can't see any upside for the energy sector of the UK coming out of the EU. The risk premium going up will increase the cost of capital," Ian Simm, chief executive of UK-based Impax Asset Management, said.
"We have mostly run our power assets down over the past 25 years. Therefore, we do need investors to be confident enough to put their hands in their pockets and commit to the next wave of power plants," he added.
UK-based consultancy Vivid Economics has estimated the cost of exclusion from the internal energy market, excluding impacts on investment, could be up to 500 million pounds ($708 million) a year by the early 2020s.
"The scale of planned infrastructure investment in the electricity sector over the next decade means that even small increases in the cost of financing could have large consequences for total investment costs," it said in a report.
"Further upwards pressure on costs would result from the likely devaluation of the pound, given the role imported goods and services play in UK energy supply."
According to a Reuters poll this month, the British pound would sink 9 percent against the dollar after Brexit. [GBP/POLL]
Britain faces serious energy supply difficulties over the next few years as coal plants have to close by 2025, the nuclear fleet is aging and weak economic conditions curb investment in new gas-fired power plants.
Renewable energy is growing, but more interconnections and energy storage are needed. The British government has estimated that the required energy infrastructure will cost 275 billion pounds by 2020-2021.
French utility EDF's plan to build two huge nuclear reactors at Hinkley Point in Britain would help plug the supply gap. The company's chief executive said earlier this year that Brexit would not change its plans, but it has not yet made a final investment decision.
"The 3.2-gigawatt Hinkley nuclear project looks to be a financing headache in any scenario, given the parlous state of EDF's share price and balance sheet," Michael Liebreich, chairman of the advisory board of Bloomberg New Energy Finance, said in a blog post.
Investment in inter connectors is also important for Britain. UK wholesale power prices are higher than the EU average, partly because interconnections with other countries are able only to supply around 6 percent of peak electricity demand.
However, efforts to link the UK's electricity grid with other European power networks could be set back due to Brexit, with some projects likely to be put on hold because Britain would no longer automatically have a say in the formulation of EU energy regulations, Norton Rose Fulbright lawyers said.
Investment in renewables could be hampered. Changes by the government over the past couple of years to renewable-energy subsidies have already dented investment in clean energy.
"There is investor uncertainty already but the only thing that gives it any kind of framing is through the UK's obligations to the EU. If I was a cleantech investor I would be concerned," said Anthony Hobley, chief executive of think-tank Carbon Tracker Initiative.
Britain could also lose access to funding for renewables, particularly offshore wind, from EU institutions such as the European Investment Bank, said Charlie Thomas, manager of Jupiter Asset Management's Ecology Fund. Such assistance last year totalled around 7 billion euros.
"But at the same time, our view is that there is significant appetite from private-sector institutional investors to step in to any funding gap," he added.
($1 = 0.7060 pounds)
By Nina Chestney
(Editing by Dale Hudson)
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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