Source: U.S. Energy Information Administration, Short-Term Energy Outlook, June 2017
Forecast world production of crude oil and other liquids in 2017 and 2018 was revised slightly downward in the June edition of EIA’s Short-Term Energy Outlook (STEO), which was issued after the May 25 announcement by the Organization of the Petroleum Exporting Countries (OPEC) of an extension to production cuts that were originally set to end this month.
OPEC’s crude oil production target will remain at 32.5 million barrels per day (b/d) through the end of the first quarter of 2018. Given the extended production cuts, EIA now forecasts OPEC members’ crude oil production to average 32.3 million b/d in 2017 and 32.8 million b/d in 2018, down 0.2 million b/d and 0.4 million b/d, respectively, from the previous STEO. Total OPEC liquid fuels production is also expected to be lower than previously forecast. However, continuing production growth in many non-OPEC countries is expected to moderate the pace of global liquid fuels inventory draws in 2017. EIA expects a small inventory build in 2018.
Inventory draws expected in the second and third quarters of 2017 suggest the possibility of some increases in crude oil prices over the coming months. However, because U.S. tight oil production is relatively responsive to changes in oil prices compared with offshore production, and even given an estimated six-month lag between a change in oil prices and realized production, higher crude oil prices in mid-2017 have the potential to raise U.S. supply in 2018.
The largest global inventory increase in the forecast occurs in the second quarter of 2018, when Brazilian and OPEC production are expected to increase by 570,000 b/d and 220,000 b/d, respectively. Supply growth in 2018 could contribute to downward pressure in oil prices as early as late 2017. EIA’s STEO forecast assumes OPEC cuts will be extended beyond March 2018 but that non-compliance will begin to grow late in 2017 and increase in the second half of 2018. Although this forecast reflects the assumption of increased non-compliance with a second production-cut extension in 2018, any extension provides some support for crude oil prices, even if only temporarily, which would partially offset downward price pressure from growing inventories.
The June STEO forecasts a 2017 average spot price for Brent crude oil of $53/barrel (b), with prices increasing to $56/b in 2018. Average West Texas Intermediate (WTI) prices are forecast to be $2/b lower than Brent prices in both 2017 and 2018. As always, all oil price forecasts are subject to considerable uncertainty. For example, EIA’s forecast for the average WTI price in September 2017 is $51/b, but analysis of options trading suggests market expectations range from $39/b to $64/b at the 95% confidence interval.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, June 2017
Note: Confidence interval derived from options market information for the five trading days ending June 1, 2017. Intervals not calculated for months with sparse trading in near-the-money options contracts.
EIA expects U.S. crude oil production to increase through 2018, averaging 9.3 million b/d in 2017 and 10.0 million b/d in 2018. The 2018 STEO forecast exceeds the previous record U.S. production level of 9.6 million b/d set in 1970. Growth in U.S. production of crude oil and hydrocarbon gas liquids has been the largest contributor to the 820,000 b/d of non-OPEC liquids supply growth from January through May 2017. Continued increases in drilling activity in U.S. shale basins, particularly in Texas, support production increases throughout the forecast.
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
There are things brewing within OPEC. At a meeting in Baku, Azerbaijan last week – which was meant to set the stage for a formal meeting in April to review the current supply deal among the 24-country OPEC+ block – the conclusion of the meeting was that the April meeting would be deferred. The review will now take place at OPEC’s regular meeting in Vienna in June, which is mere days before the current supply deal is scheduled to end. That’s cutting it close, but more interesting for market observers is that it points to the Saudi Arabia-Russia bromance souring.
Prior to the meeting, Saudi Arabia had gone on record to state that the Kingdom believed that OPEC’s job in rebalancing the oil market was far from over and that output cuts were necessary to continue into the second half of 2019. Defying US President Donald Trump’s Twitter tantrums – especially with the Kingdom implicated in the assassination of Saudi dissident Jamal Khashoggi – Saudi Arabia is firmly behind continuing restricted supply. In the past, Saudi Arabia would most likely to be able to bully its way into an OPEC consensus. But now, it has to deal with an equally powerful 20-ton gorilla in the same room: Russia.
The success of the OPEC+ club over the past two years has been down to this close relationship between the world’s two largest oil producers. This had allowed crude prices to recover from sub-US$50/b levels. But the latest meeting is also the latest sign that all may not be well in the friendship. First, a joint Saudi-Russia meeting at the World Economic Forum in Davos was called off. Second, February data showed that while Saudi Arabia and its allies were doing far more than necessary to cut their crude production, Russia was shuffling its feet with less than 50% adherence, claiming that it needed more time to implement the cuts. And last week, despite Saudi Arabia lobbying for an extension to the cuts and general backing from members including Iraq, Russian Energy Minister Alexander Novak was in opposition. The official reason was that OPEC+ would need clarity on market situation before planning the next move, given the disruption brought about by ongoing and developing American sanctions on Iran and Venezuela. In the absence of necessity, the two crude powerhouses have drifted back to their default positions: Saudi Arabia’s aggression and Russia’s conservatism.
So while the world waits and watches for OPEC+’s next move, the market is analysing the potential impact of a strained Saudi-Russia relationship. But necessity might bring the two back together again, since they now face a common foe – rising US crude production. OPEC’s secretary general recently met with key executives in the US shale oil industry. This was billed as a ‘friendly conversation on current industry trends’ and interpreted as an attempt to cajole American shale producers in a mutually-beneficial stabilisation of the market. It is ridiculously unlikely for the US to ever join the OPEC+ club, but if the move could convince US shale firms to temper their expansion to prevent global oversupply, it might be worth it. Because OPEC has accompanied the olive branch with a threat – if OPEC does all the work to stabilise markets only to have American shale take advantage of the situation, it could very well reverse its stance and turn the OPEC tap on full to swamp the market once again. It’s a classic example of game theory, and one to watch as the power dynamics of global oil continue to change.
Key upcoming dates for OPEC:
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