Oil prices will be lower for longer—that is the conventional wisdom. Data suggests, however, that oil supplies are tightening and that higher prices are likely in the relatively near-future.
Refined Product Demand and Crude Oil Exports
U.S. crude oil plus products comparative inventories have fallen 120 mmb (million barrels) in 26 of the last 32 weeks (Figure 1). Strong domestic demand for refined products and increased crude oil exports are the main reasons. That translates into lower net imports of both crude oil and petroleum products to the United States. The year-to-date average of U.S. product net imports is down 0.5 mmb/day from 2016. That’s 3.5 mmb/week which is about the average weekly storage withdrawal since mid-February.
Figure 1. Approximately 3.3 mmb/week (470 kb/d) Decrease in Net Petroleum Product Imports Account for Most Inventory Reductions in 2017. Comparative Inventories Have Fallen 126 mmb Since Mid-February. Source: EIA and Labyrinth Consulting Services, Inc.
U.S. crude oil exports have increased reaching a record 1.9 mmb/d during the week ending September 29 (Figure 2).
Figure 2. Record Crude Exports of 1.9 mmb/d Week Ending Sept. 29 2017. Source: EIA and Labyrinth Consulting Services, Inc.
Increased exports have been part of how producers cope with limited U.S. refining capacity for the ultra-light oil from tight oil plays. Recent increases in exports levels, however, are because of higher international oil prices compared with domestic prices.
Brent has traded at a premium to WTI since U.S. tight oil became a factor in global supply in late 2010. That was largely because of limited take-away and refining capacity for the new U.S. supply in the early days of tight oil production. The Brent-WTI “spread” reached $28 per barrel in September 2011 but decreased when infrastructure caught up with supply. It averaged about $1.68 in the first half of 2017.
In June, the spread began increasing and is currently almost $7 per barrel (Figure 3). Some of this is a “fear premium” because of tensions in the Middle East—the GCC boycott of Qatar and the Iraqi Kurdish independence referendum. Some of it is also a buildup of inventories at the Cushing, Oklahoma storage facility and WTI pricing point.
Figure 3. Brent Premium to WTI Has Increased More Than $5/barrel From 1H Average. Middle East Fear Premium plus Cushing Inventory Levels are the Cause. Source: EIA and Labyrinth Consulting Services, Inc.
Inventory increases at Cushing may be partly explained by refinery and pipeline outages following recent hurricanes but the build ups actually began in July a month before Hurricane Harvey. The causes are not entirely clear but rising inventories at Cushing especially when its storage exceeds 80% is generally a negative factor for WTI prices.
In addition to crude oil, exports of distillate, liquefied petroleum gases, and liquefied refinery gases have also increased in 2017.
Comparative Inventories and The Yield Curve
Falling U.S. comparative inventories (C.I.) in 2017 is a trend and not an anomaly. Figure 4 shows the 120 mmb decrease in C.I. since mid-February and the associated “yield curve” (Bodell, 2009) that correlates inventory with WTI price.
Figure 4. U.S. Crude + Product Comparative Inventory Has Fallen 120 mmb Since Mid-February–Yield Curve Suggests Higher Oil Prices Sooner Than Later. Source: EIA and Labyrinth Consulting Services, Inc.
The magnitude of the inventory drawdown cannot be over-stated. The fact that it is driven by increasing demand suggests that that U.S. supply is moving steadily toward balance.
OECD comparative inventory (less the U.S.) has fallen 99 mmb since July 2016 (Figure 5). Although the data frequency is lower (monthly vs. weekly) and less systematic than U.S. inventory data, the reduction in C.I. is the main point.
Figure 5. OECD (minus U.S.) Comparative Inventory Has Fallen 99 mmb Since July 2016. Source: EIA, IEA and Labyrinth Consulting Services, Inc.
The relative lack of price increase with falling C.I. for both the U.S. and OECD is because the yield curve was flat for much of the reduction because of the the magnitude of storage volume. Now, enough inventory has been drawn down that the curvature of the trend is increasing. Greater price response with incremental reduction in C.I. is likely as volumes approach the 5-year average.
Misplaced Concern About Shale Supply
Fears about burgeoning U.S. supply from shale reservoirs has been a consistent drag on market sentiment about price for at least a year. This has been based more on rig count than real evidence. Continental Resources chairman Harold Hamm has loudly blamed overly optimistic EIA supply forecasts for low U.S. oil prices. This is misplaced and typical of the hyperbole regularly heard from shale company executives.
The fact is that U.S. output has been flat since early 2017 and the EIA has adjusted its forecasts as data replaces sampling algorithms in their accounting (Figure 6).
Figure 6. U.S. Output Has Been Flat in 2017. Source: EIA and Labyrinth Consulting Services, Inc.
The reason is that despite increased drilling, frack crews and equipment are not sufficient to meet demand for well completions. Pressure pumping equipment was not maintained and parts were cannibalized after the oil price collapse, and crews were laid off. It may take another year of strong demand to rebuild this capacity.
The result is that far more tight oil wells are being drilled than completed and I expect that this pattern will continue (Figure 7).
Figure 7. More Permian Wells Have Been Drilled Than Completed in 2016 and 2017. The Number of DUCs (Drilled Uncompleted Wells) is Increasing. Source: EIA and Labyrinth Consulting Services, Inc.
Fears that DUCs (drilled uncompleted wells) will flood the market with supply are unrealistic. When these wells are completed, it will be gradual and the natural ~30% annual decline in legacy shale production will be difficult to overcome. Moreover, production from the Eagle Ford and Bakken plays is declining. Only Permian production is increasing and on balance, it is unlikely that net shale production will increase much unless production trends outside the Permian basin somehow reverse.
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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
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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