The current collapse in crude oil prices is unparalleled in recent history. Risks at current price levels appear to be more balanced, although we expect further consolidation in the oil production industry before prices can start to normalise over the long term. This article contextualises today’s market situation and updates our outlook from last year.
In a nutshell, prices have undergone a major adjustment, but this has not yet been adequately reflected in reduced production capacity. Volatility has been limited to financial markets with limited spill-over into real production capacity. This suggests to us that US producers have not yet adapted to the new price paradigm. For prices to start normalising producers need to align their production to the new landscape.
Exhibit 1: The recent collapse in oil prices constitutes a major disruptive event for the oil industry (West Texas Intermediate (WTI) futures contract for the period from January 2000 through 9 February 2016).
Source: Bloomberg, Datastream as at January 2016.
Price discovery in crude oil markets
To help readers understand our current outlook on the oil markets, it is worth reconsidering three points from our briefing note in February 2015:
(1) the rise of shale oil,
(2) OPEC’s changing behaviour
(3) the impact OPEC’s new stance has on how markets determine oil prices.
To begin with, the advent of shale oil extraction constituted a major disruptive events in oil markets as the costs-to-market of shale oil are lower than those of deep water or oil sand projects (see exhibit 2). Taking into account its scale of resources and future production growth potential, shale oil had become the new marginal supply.
One of the consequences of this structural disruption has been the shift in focus of OPEC/Saudi Arabia’s revenue maximising strategy from controlling prices to controlling volumes (i.e. market share).
One of the consequences of this structural disruption has been the shift in focus of OPEC/Saudi Arabia’s revenue maximising strategy from controlling prices to controlling volumes. In other words, Saudi Arabia’s revenue maximising strategy is no longer to reduce production to hold up prices but to stabilise and regain its market share.
In the absence of OPEC output management, the only mechanism to move markets back into equilibrium is market forces. Given the current global physical oversupply, prices need to remain sufficiently low so as to bring producers to the point where they can no longer bear losses and therefore, begin to shut down production (cash cost at around USD 35-45 per barrel (bbl)).
Exhibit 2: An analysis of global oil production costs, by producer type at the end of 2014
Source: Redburn, BNP Paribas IP, as of FY 2014
No pain, no gain: oil fundamentals ended year unchanged
Prices have fallen significantly lower from pre-2014 incentive levels of around USD 85/bbl to today’s cash cost pricing levels (see exhibit 2). Despite this marked adjustment, market fundamentals (i.e. the balance of supply and demand) remained broadly unchanged in 2015.
As anticipated, demand was stable and strengthened with falling prices. However this demand-side improvement was offset by increasing supply from OPEC member states.
Surprisingly, US production – which we regard as marginal supply in a global context – remained resilient to this price pressure, declining only marginally by 150 000 barrels per day (bpd) relative to a global oversupply of 1 500 000 bpd.
Although we signalled last year that there can be a time lag between movements in financial markets and real production, we did not expect to see such minor adjustments, especially when considering the short production cycles of US shale oil.
Production remained resilient, yet…
Unlike the oil price crises that have occurred in past decades, the impact of the current price crash has been cushioned to some degree by various economic and financial structural improvements including flexible exchange rate regimes, advances in capital markets and the internationalisation of trade and oil market.
With more emerging markets (e.g. Russia, Mexico) now using flexible exchange rates, currencies have become an important factor in smoothing the falling-off-a-cliff of US dollar-denominated commodity revenues. As their currencies have quickly devalued, non-USD producers have experienced oil prices similar to those of two years ago (exhibit 3), while USD producers have had to cope with a 60% drop in their reference prices.
Exhibit 3: Oil impacts depends on reference point: long-dated WTI prices in US dollar and local foreign exchange terms
Source: BP, BNP Paribas IP as of 01/2016
That being said, producers – particularly in the US – have benefited from deeper and more liquid capital markets which have allowed them to transfer their capital risk by selling future production. Compared to the 1990s, companies were better hedged going into 2014/15. These hedges will however expire over the course of 2016.
In response to falling revenues, US shale producers have also started to ‘cut corners’ by eliminating less efficient rigs first (‘high grading’). This only constitutes a temporary fix and the impact, in our view, should start to fade soon.
So far, a few US producers have experienced financial difficulties. Although a high degree of private equity interest in them means distressed assets have tended to be the subject of a passing-of-the-parcel rather than simply being shut down.
Factors that have until now protected the US shale industry from the impact of slumping oil prices, are beginning to receed. With capital markets now seemingly closed to most players and rating agencies such as Moody’s putting most energy-related companies on ‘review for downgrade’, it appears we are nearing a turning point.
Falling production costs impact long-term equilibrium price
Once the equilibrium between supply and demand in physical markets begins to tighten, prices should start normalising towards what we see as the long-term equilibrium price of around USD 55/bbl, based on US shale production costs. We have revised down our estimation of the long-term equilibrium price by USD 10/bbl compared to our outlook from last year. This revision is based on the significant cost efficiency gains we have seen in shale technology (exhibit 4).
Exhibit 4: Illustration of the significant cost improvements achieved in shale extraction: change in Matador’s total oil uplifting costs between the first half of 2014 and the first half of 2015
Source: Matador Resources, company data, April 2015
Moreover, there is potential for further significant cost savings through the application of big-data analytics for shale extraction and tighter cost control by large oil companies. An indicative example for significant cost deflation can be seen with traditionally expensive deep-water projects, where the costs of new developments have fallen from around USD 85/bbl in 2014 to around USD 55/bbl today (exhibit 5).
Exhibit 5: Significant cost deflation: how the breakeven price for oil production from a typical deep-water development has fallen between 2014 and 2015
Source: Redburn, BNP Paribas IP, as of 2015
This challenges the cost curve shown in exhibit 1, placing downward risk on long-term equilibrium prices.
Risk to demand: acceleration of fuel subsidy reforms
While our focus is on supply, there is a risk that lower prices may actually result in lower demand: the current, generous fuel subsidy programmes are becoming unaffordable for many oil producing countries as their oil revenues shrink.
Countries subsidising oil for their domestic consumsers typically exhibit an inflated demand for oil – on average 2.5x higher oil per capita consumption – giving risk to a drop in fuel demand as reforms are imposed – as seen in Mexico, Malaysia or Russia.
If subsidy reforms were to accelerate it would delay a rebalancing of market forces. However, for the purposes of this analysis we exclude this factor.
Low prices are the best cure for low prices
In a ‘typical’ scenario of demand growth, the supply-side surplus would not, in our view, last for very long. However, this ignores the prospect of another year of strong supply as Iranian supplies return to global oil markets.
There have also been storage capacity concerns connected to fears of prices dropping below USD 20/bbl. However we see this as a tail risk; globalisation has helped to create more oil outlets, leaving markets with sufficient storage capacity to deal with a more prolonged rebalancing period.
To avoid capacity limits eventually being breached (should OPEC not reduce output), the oil markets require a decline in physical production. There are early signs of a down turn in US supply. If prices remain below USD 40/bbl and Iran’s oil exports are not unexpectedly abundant, we believe oil markets should balance out towards the end of 2016.
Once excess capacity is cleared, the markets will start drawing down inventories and thus gradually begin to revert to a price level that incentivises new production. Having said that, the resource additions from shale players in recent years can more than satisfy demand for the foreseeable future and consequently even in a bullish scenario we anticipate that any price rebound would be capped at around USD 55/bbl.
Asset allocation implications
On a broader scope, we have started 2016 more cautiously positioned on market risk. We see this as justified by the mix of heightened valuations, the prospect of a low growth environment and increasing divergence in growth and liquidity.
The low-growth outlook already reflects the positive impact of lower commodity prices and this effect should persist as long as oil markets rebalance and prices remain below USD 40/bbl.
It is therefore our view that today’s oil market slump is mainly supply-induced. For this reason we do not interpret it as an indicator of weak underlying global economic activity.
While the physical oil market finds its way back to equilibrium we anticipate further heightened oil price volatility in the short-term before oil prices begin to stabilise later this year. This should counter fears of deflation and support the US Federal Reserve in pursuing its monetary policy agenda.
US shale-oil producers appear to be bearing the brunt of required oil production reductions, which is likely to result in significant financial stress and credit events in the industry. However, with a yield of 9.5% and an option-adjusted spread of 750bp, the aggregate prices of US high-yield debt already reflect sufficient default risk to compensate for the uncertainties in the oil sector, even if oil prices do stay ‘lower for longer’. Additionally, energy-related names account for only a small portion of US credit (around 10%).
Equities, on margin, should continue benefiting from the indirect effects of low oil prices (stronger demand, lower input costs). At the sector level, we see a potential investment opportunity for integrated oil companies, particularly as markets do not seem to fully appreciate their ability and aptitude to control costs. For the moment however we think it is still too early to pursue this route given heightened valuations and the outlook for elevated oil price volatility in the coming months.
On a relative basis, emerging market oil-related assets should benefit the most from stabilising prices since they have lost more value than those of their developed peers and emerging market (EM) debt has a relatively high commodity exposure (the weight of oil-linked countries in EM local debt is around 35%, in EM hard currency debt 25%).
It is likely this will only be a temporary effect. We maintain our underweight bias to emerging market assets given the overhang of excess capacity in their economies and a corresponding lack of earnings and economic stability. Looking more specifically at emerging market debt, the outlook of oil prices being capped longer-term at around USD 55/bbl raises questions on debt sustainability since many emerging market oil producing countries require oil prices of USD 65/bbl or higher to achieve a fiscal breakeven.