Oil: The price is not right

The market wants to trade a demand slow-down of the future, while ignoring the fundamentals of the present

Until recently, 100m barrels a day of global oil-product demand seemed a distant prospect. In its World Energy Outlook , published in November 2016, the International Energy Agency‘s (IEA) central scenario didn’t think consumers would reach this landmark before 2024. Strong recent tailwinds—particularly from China, India, the US and Europe—have, however, brought the milestone perilously close. We think it will be reached by mid-2018.

The IEA isn’t alone in having underestimated global demand. Take your pick from Opec, BP, ExxonMobil or any of the more oft-quoted long-term analysts: none forecast 100m b/d of demand much before 2022, with most putting its arrival between 2024 and 2026. Opec’s 2016 World Oil Outlook cited 2022 as the likely first sighting of 100m b/d, and forecast average demand growth of 1.0m b/d per year between 2015 and 2021, well below what was realised over 2015-17. As for the IEA, its 450 Scenario—in which policy would limit average global temperature increase to 2°Celsius above pre-industrial levels—says demand would never hit 100m b/d. Even in its Current Policies Scenario, it doesn’t happen till 2020. These mandarins of long-term forecasting failed to capture the recent upsurge in demand growth because their models were built on a dated premise of ever more efficient oil use. But that was a legacy of a decade of high prices.

Before 2015, with the odd exception such as the temporary rebound in 2010 that followed the Great Recession, global oil-demand growth had been on a slowing trend and most demand-side models reflected this paradigm. Indeed, in 2014, consumption rose by just 0.8m b/d, raising widespread fears (among oil producers) that efficiency gains were here to stay. At that point, most assumptions (including ours) gravitated towards 1m b/d of annual average growth each year through to 2020—we saw that as a best-case scenario. Wrong. As prices plummeted from mid- 2014, consumer behavior rapidly evolved. Cheap feedstocks fed a thriving petrochemicals sector, while drivers worldwide, and especially in the US and China, shunned more efficient vehicles for SUVs and other gas-guzzlers.

According to auto-research company Edmunds, in 2015 and 2016, 40% of hybrid or electric-vehicle (EV) trade-ins in the US were for SUVs or trucks and over 10% for luxury cars. In turn, oil demand grew by 2.1m b/d in 2015, 1.8m in 2016 and should see out 2017 with growth of another 1.6m. Annual average growth between 2015 and 2017 will have been 1.8m b/d—almost double the forecasts just three years ago. Simply put, $50-a-barrel oil has proven too cheap, particularly against the now robust economic backdrop. Instead of growing to 98m b/d by 2020 ( from 92m in 2014) demand will average 100m b/d by H2 18. And it doesn’t look likely that oil-demand growth will flatten out in 2018 either. Barring a sudden recession or sharp rise in the oil price, the year will add 1.5m b/d of consumption.

That being so, the real question for the market is whether supplies will be able to keep up. American tight oil production is often quoted as the major source of new output growth—the IEA expects it to add 1m b/d between 2015 and 2020, with similarly sized additions forecast through the late 2020s and an underlying oil price of $130/b needed to squeeze out an extra 1m b/d by 2025. We forecast tight oil adding exactly 1m b/d between 2015 and 2020, reaching a cumulative 6.2m. If prices rise sharply, that growth could be over 2m b/d. That’s a lot. But it’s not enough. The fear in the market is that $50-55 oil will unleash a torrent of shale that will overwhelm demand. But look again at the demand-growth trend of recent years. If demand is growing three times as quickly as tight oil output, shale on its own won’t be able to plug the gap. Some of shale’s shine has come off recently too. Several banks have begun changing their tune on tight oil breakevens and many equity analysts are starting to downgrade their producers. The tide seems to be turning somewhat. Add in some high-profile fund managers betting against a number of American tight oil firms, and suddenly infinite growth from the

American shale oil patch is no longer a given. As a group, tight oil producers have not made money. The 51 US E&P companies we track together spent $18.2bn on capex in the second quarter of 2017, while cashflow from operations was $12.2b – negative free cashflow of $5.9bn. Nor was Q217 an anomaly. Simply put, these firms have never been able to fund themselves with cash generated from oil and gas production. This is not a dirty little secret; it is a common feature of businesses in growth mode in a multitude of sectors unrelated to oil and gas. Still, an oil-production growth model is neither sustainable nor can it generate value for investors if low oil prices become a long-term structural feature of the industry. Ultimately, “lower for longer” means that the discounted cashflows for these businesses remain negative, and therefore their attractiveness as a potential value-generating stock in a portfolio are diminished. These factors influence appetite for E&P debt and equity, which are the two key determinants of production growth because they, rather than cashflows from operations, fund drilling programmes for companies in growth mode.

In other words, when there is no money there is no growth. If E&P stocks fall because investors doubt their capacity to generate future value, then the value of potential equity funding drops as well, meaning less cash is available to fund operations. If E&Ps issue more debt, their interest payments rise (drawing cash from the business) and investors become concerned over firms’ debt positions, diminishing demand for the stock. This was a key concern in 2016, when low oil prices caused borrowing-base redeterminations and lenders cut revolving credit lines, reducing the cash pile available to fund drilling. While E&Ps have made strides to reduce their debts and shore up balance sheets, they have done so by selling more equity.

Based on the guided H217 and 2018 crude production ramp-up for our sample group and the current forward strip, these shale firms will not be funding drilling programmes through operating cashflows anytime soon. This means they are likely to continue tapping debt and equity markets for finance, adding to a debt pile that already stands at $120bn. And investor appetite for exposure has been sliding. Since the start of 2016, an investment in a basket of E&P firms would have underperformed the S&P 500 and WTI crude oil significantly. This tells us two important things: first, that macro investors seeking a benchmark-beating return would have been better rewarded by putting their money elsewhere.

Second, oil investors would have been better off just buying oil futures. The problem with the oil market right now is that it wants to trade the next decade’s potential slowdown in demand, but ignores the fundamental reality in front of it today. We don’t deny that demand growth can slow materially from around 2026 as the penetration of EVs and hybrids becomes material to transportation demand. But investors remain transfixed by an as-yet-unrealised energy revolution, and they are not paying attention to the supply side’s ability—or inability—to meet today’s demand for oil. Once the last of the legacy projects come onstream, there is little new investment on the horizon outside the shale sector.

If demand does not slow, the world will need far more oil than the tight oil sector can offer at $50/b. Without additional productive capacity, rapidly growing consumption could trigger a supply crunch well before the theoretical peak in oil demand is reached. We are not saying for one moment that there is too little oil—there is plenty. There just isn’t enough oil at $50/b.

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