Energy and Oil Developments 


Weaker physical market indicators outside the US are disconcerting. While the market has focused on better US inventory trends of late, the global market is quietly showing signs of stress. The US draws are primarily a result of low imports on the back of unsupportive economic arbs in recent months. Yet this lower US import level and returning supply (which is only now showing up for export in Nov) appear to be taking some toll on global markets. The problem appears to be most acute in the Atlantic Basin.

Prompt Brent time spreads eroding. The prompt time spread is now at its lowest level YTD (other than expiry), despite field maintenance. North Sea field maintenance was responsible for the strength / backwardation earlier this year, but maintenance is now fading, adding to North Sea supply. The return of light crude barrels from Libya and Nigeria, along with lower US imports are all also likely contributing to the congestion. Crude differentials are weakening too. Beyond structure, North Sea differentials are all weaker in recent weeks as well. West African crude differentials have also been fading, with some grades now pricing at similar levels to early 2016. Thus, it’s not surprising that Bloomberg reported an abnormally high number of tankers (as many as 10) in the North Sea waiting on transfers. The primary challenge is that Atlantic Basin loadings are finally recovering. Refinery maintenance isn’t the primary issue. The market is currently trading Dec-16 Brent, which should reflect a period of elevated refinery demand. Rather, crude loadings (which are more important than production) are only now recovering in West Africa, the North Sea and Libya after being at low levels from May-Oct. This is why many recent inventory data points citing bullish inventory draws are simply backward looking.

 Rising tanker rates add to the problem as the arb to Asia becomes more expensive. The backlog should clear with appropriate price signals, but it also suggests oversupply risk persists. If Atlantic Basin differentials shift enough, these barrels will find a home. The US import arb appears to be opening back up. Asia also has an appetite for these barrels when the arb is open, and refiners are coming out of maintenance. However, such changes just shift the inventory picture regionally. The Dubai curve offers a mixed picture. Typically, Dubai reflects Asian demand. Front month spreads are volatile with spot purchases and have moved into backwardation after being weak into the roll in early Oct. Yet, the more stable Dubai 2-3 is weakening.

Total rig count and time lags continue to distort the magnitude of US response. The growth rate of more productive horizontal rigs has continued unabated, with volatility coming in vertical and directional rigs. For example, talk of slowing total rig additions in the Permian misses the true trend. Horizontal rigs in the Midland Basin have increased by 14 since early Sep, whereas vertical rigs have declined by 4 and directional rigs are flat. Rigs are also moving to the most productive acreage. Top IP counties in the Midland Basin now have a rig count above pre-downturn levels and only 12 below all-time highs. We should see rig counts continue to increase in the wake of the recent price rally and hedging, but with a lag. Rig counts typically lag prices by 3-4 months, so we would expect to see more rigs added, especially near year-end. Since prices also spur producer hedging, a similar lag exists between rigs and the 12-24 WTI time spread. The correlation between the 4-6-month lagged rig count and the WTI spread is 0.85-0.87 since 2012. The time lag can be longer with horizontal oil rigs due to logistics and pad drilling time, as well as the mix shifts we saw in recent years. Yet, all items point to increased hedging, as well as production growth in 9-12 months time. Commercial shorts reached the highest levels since early April, and the 12-24 spread is approaching YTD highs. The recent rise in horizontal rigs and hedging at increasingly lower thresholds is indicative of lower breakevens and the US potential. In mid-2015, producer hedging was significant at $65. Now we tend to see large amounts of hedging in the low-to-mid 50s. And yet, well productivity has the potential to rise substantially from here. In other words, the US cost curve has moved lower in this downturn and could move even lower over time.

Moreover, a more modest US production decline related to OPEC intervention reduces the need for a sudden and large US response, which suggests fears of a large oil services crunch and cost inflation, or a supply shortfall, are being partly mitigated. We are increasingly in the Exxon camp, as US shale’s disruptive nature remains underappreciated. Many bullish arguments we hear on US tight oil are similar to those we heard in natural gas from 2012-15, and increasingly we see similarities with the development of new basins, shifting capital allocation and productivity gains.