Last week, OPEC sounded an alarm. Previously hopeful that the global crude markets would be balanced by June, which would allow it to walk back on the supply freeze that propped prices up at the cost of OPEC market share, the OPEC monthly report raised its expectations for non-OPEC supply for a fourth consecutive month. OPEC now expects global oil demand to grow by 1.6 mmb/d this year, which is more than previously expected. However, non-OPEC oil supplies will grow by 1.66 mmb/d, more than covering demand. The culprit, as always, is the US, where output is expected to grow by 12%. And this is not even the most optimistic forecast; the IEA expects non-OPEC supplies to grow by 1.8 mmb/d this year.
While this has near term implications – Saudi Arabia has already signalled that the OPEC supply curbs may have to extend into 2019 – the more important question is, how far can shale go? American oil production can consistently surpassed expectations over the past year, as the recovery in oil prices triggered a return rush to shale drilling. This will help US oil production reach 11 mmb/d by Q418; it could be even earlier, based on current production trends. By 2030, BP expects US shale oil to grow to 10 mmb/d, almost double its current level.
Despite the base case for shale production being constantly revised upwards – requiring lower long-term oil prices to clear – it is worth asking how realistic it is. There are suggestions that American shale production could hitting the wall; not because the of finite reserves in the Permian, but because of technology limitations. The application of new technology does not in itself create new energy, it only improves the recovery of hydrocarbons and at a faster rate. As reported in CNBC, "Mark Papa, a pioneer in the U.S. shale oil revolution, is warning that forecasts for booming U.S. production growth will leave industry watchers disappointed in the coming years as drillers burn through their best wells and tighten their purse strings. The impression of U.S. shale as the big bad wolf is perhaps a bit overstated, Papa told an audience at this year's CERAWeek by IHS Markit in Houston this year. Papa's comments were a stark contrast to the tone of cautious optimism at the conference, where many executives claimed that data analytics and technology, like machine learning, will improve efficiency in the oil patch and fuel further gains." Most people are focused on additions to the US rig count, productivity rates in shale wells are actually declining, while costs per well are rising. Major players seem to be mitigating this by creating larger fields by connecting wells, but there is also a looming logistical and manpower crunch. The WSJ reports that "Oil infrastructure is the most glaring constraint to limitless growth in U.S. shale output, said analysts for Energy Aspects in a recent note. The Permian basin had 10 oil takeaway pipelines with a combined capacity of 2.92 million barrels a day as of February 2018, said analysts. There will be a shortage of takeaway capacity in the Permian by August, which will only get worse into year-end, noted experts." This suggests that while shale production is still on the steep part of its growth curve, that could soon plateau out and that long-term forecasts are overstated. That would be good news for oil prices in the long run.
However, there are signs that the opposite could be true. Investment into shale players is increasing, giving them more funds to play with. With money, come more interest – solving, or at least, mitigating most of the upcoming bottlenecks. It seems that either more debt through borrowings or the capital markets is driving this production surge, particularly in the USA. However it is worth noting that the USA is not the only place the shale revolution is taking place. By the end of this month, Saudi Arabia will have produced its first shale gas from the North Arabia basin. The giant South Ghawar and Jafurah basins – which reportedly rival Eagle Ford in size – are also underway. Promising finds are improving moods in China and Argentina shale as well, while the UK drilled its first shale well last year. Even if the American shale revolution hits the brakes, the movement could continue elsewhere, which would mean that current non-US share oil production forecasts maybe understated? There is little data out there about the profitability or economics of non-US shale fields.
Both the low and high scenarios make compelling cases. Both, however are closely tied to current developments in US oil production. Ultimately the base case for shale will depend on economics but more importantly the demand for hydrocarbons in the medium to long term. If oil demand keeps growing, so will the need for more oil, but any large surge would only dampen prices all over again, effectively killing shale production. So can shale go far, technically possible, as there are proven reserves all around the world that are still untapped. But like with everything else, it's the economics and geopolitical factors that will define its days ahead.
Various production forecasts for American shale tight oil production
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Headline crude prices for the week beginning 11 November 2019 – Brent: US$62/b; WTI: US$56/b
Headlines of the week
The year’s final upstream auctions were touted as a potential bonanza for Brazil, with pre-auction estimates suggesting that up to US$50 billion could be raised for some deliciously-promising blocks. The Financial Times expected it to be the ‘largest oil bidding round in history’. The previous auction – held in October – was a success, attracting attention from supermajors and new entrants, including Malaysia’s Petronas. Instead, the final two auctions in November were a complete flop, with only three of the nine major blocks awarded.
What happened? What happened to the appetite displayed by international players such as ExxonMobil, Shell, Chevron, Total and BP in October? The fields on offer are certainly tempting, located in the prolific pre-salt basin and including prized assets such as the Buzios, Itapu, Sepia and Atapu fields. Collectively, the fields could contain as much as 15 billion barrels of crude oil. Time-to-market is also shorter; much of the heavy work has already been done by Petrobras during the period where it was the only firm allowed to develop Brazil’s domestic pre-salt fields. But a series of corruption scandals and a new government has necessitated a widening of that ambition, by bringing in foreign expertise and, more crucially, foreign money. But the fields won’t come cheap. In addition to signing bonuses to be paid to the Brazilian state ranging from US$331 million to US$17 billion by field, compensation will need to be paid to Petrobras. The auction isn’t a traditional one, but a Transfer of Rights sale covering existing in-development and producing fields.
And therein lies the problem. The massive upfront cost of entry comes at a time when crude oil prices are moderating and the future outlook of the market is uncertain, with risks of trade wars, economic downturns and a move towards clean energy. The fact that the compensation to be paid to Petrobras would be negotiated post-auction was another blow, as was the fact that the auction revolved around competing on the level of profit oil offered to the Brazilian government. Prior to the auction itself, this arrangement was criticised as overtly complicated and ‘awful’, with Petrobras still retaining the right of first refusal to operate any pre-salt fields A simple concession model was suggested as a better alternative, and the stunning rebuke by international oil firms at the auction is testament to that. The message is clear. If Brazil wants to open up for business, it needs to leave behind its legacy of nationalisation and protectionism centring around Petrobras. In an ironic twist, the only fields that were awarded went to Petrobras-led consortiums – essentially keeping it in the family.
There were signs that it was going to end up this way. ExxonMobil – so enthusiastic in the October auction – pulled out of partnering with Petrobras for Buzios, balking at the high price tag despite the field currently producing at 400,000 b/d. But the full-scale of the reticence revealed flaws in Brazil’s plans, with state officials admitting to being ‘stunned’ by the lack of participation. Comments seem to suggest that Brazil will now re-assess how it will offer the fields when they go up for sale again next year, promising to take into account the reasons that scared international majors off in the first place. Some US$17 billion was raised through the two days of auction – not an insignificant amount but a far cry from the US$50 billion expected. The oil is there. Enough oil to vault Brazil’s production from 3 mmb/d to 7 mmb/d by 2030. All Brazil needs to do now is create a better offer to tempt the interested parties.
Results of Brazil’s November upstream auctions:
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