Crude oil market briefing: lower for longer?

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Please note that this article may contain technical language. For this reason, it is not recommended to readers without professional investment experience.

The plunge of more than 50% in oil prices in the six months to January 2015 is an extremely unusual economic event for a commodity at the heart of the modern global economy. In seeking to understanding the cause, much of the market’s focus has been on the weak global demand for oil, the rise in supply of shale oil and OPEC’s changing behaviour. In this note we put these issues into context and provide our outlook for oil prices.

To summarise, we believe markets are experiencing a temporary glut created by a surprise improvement in production from producers impacted by the Arab Spring. Contrary to most commentators though, we do not expect to see a rapid bounce back once this excess supply is worked off, but that there has been a fundamental change in the incentive price required to balance supply and demand in the oil market.

Consequently, while we think oil prices are currently close to the bottom, we anticipate that we are dealing with a sustained period of sub-USD 65 (per barrel of WTI ) oil for the coming years.

A conceptual framework for analysing oil prices

Key to understanding the oil price is the interplay between the ‘incentive price’ and ‘cash costs’:
•      When there is a physical deficit, the oil price must rise to a level whereby producers are convinced that by investing in new production, they will make an attractive return on their capital (the incentive price).
•          When there is a physical surplus, the price must drop to a level at which higher cost producers can no longer bear the losses to which they are subject and thus begin to shut down production (i.e. below cash costs).
The incentive price will always be higher than cash costs (c. USD 80 vs. USD 45 at the 90th percentile) since calculation of the former includes both the initial investment and the ongoing operating costs, while the latter only relates to operating costs. Global crude oil production costs are shown in Exhibit 1.

Exhibit 1: Global oil production costs (2014)

Oil Chart 1

Source: Redburn, BNPP IP, as of 10/02/2015

Over time, because existing oil production naturally declines (at around 5% a year) and demand tends to grow, there will be a tendency for the oil price to move towards the incentive price. Occasionally, however, when there is a negative demand shock or an unexpected increase in supply (as in the current situation), the market can move into surplus and the price will rapidly fall to cash costs until supply adjusts.

The recent oil price move in context

If we look across the period since the start of the millennium it would be reasonable to say that the energy industry has been characterised by growing global demand driven by expanding emerging markets, with supply struggling to keep pace. As a consequence, the cost of extraction, and thus the incentive price, has been steadily rising as the industry has turned to more complex, marginal extraction fields to fill the void.

Oil prices continued rallying until 2008 when a negative demand shock caused by the global financial crisis pushed the market balance into excess supply. This caused a temporary reversion to cash costs. As we have seen in previous cycles, a consequence of this is that some of the more marginal ‘stripper’ wells[1] shut down production (see Exhibit 2).

Exhibit 2: US stripper wells production 1975-2000

Chart 2

Source: BP, EIA, Bernstein, BNPP IP, data up to 2000

With the subsequent rebound in demand, the market moved back into deficit and the price once again reverted towards the incentive price band for five years – fluctuating predominantly on the basis of geopolitical risk.

During that period we saw the emergence of ‘shale oil’ extraction, which has grown from nothing to five million barrels per day (bpd) in just five years.

With an incentive price of between USD 55-65, this alone would have proved to be extremely deflationary to oil markets were it not for the fact that it has masked an unusually high level of supply disruptions in the Middle East and Africa amounting to around three million bpd (see Exhibit 3).

Exhibit 3: US oil production & global supply disruptions

Chart 3

Source: EIA, US Department of Energy (DoE), BNP Paribas IP, data up to 12/2014

Despite shale being the most commonly cited reason for the latest fall in the oil price, the reality is that the most recent period of growth was largely anticipated by analysts. What was not expected was an improvement in previously disrupted production from Africa and the Middle East (e.g. Libya), coupled with a more stable outlook from high decline areas (Norway, UK).

The coinciding of such an improvement in supply with moderating demand expectations led the market consensus to move from expecting a roughly balanced market in 2015 to the anticipation of a circa 1.25 – 1.50 million bpd surplus by mid-year.

Initially the price reaction, while sharp, was not meaningfully outside of the norm as markets expected OPEC (and specifically Saudi Arabia) to cut production in order to maintain prices and balance their budgets, as they had in the past four decades.

With the announcement that no such cut would be forthcoming and the suggestion that the new focus would be on market share, it became clear that the only mechanism for price discovery under the expected surplus volume would be market forces.

As is typical for products such as oil with low demand and supply elasticity, prices can be subjected to large and forceful swings when fundamental mechanisms alter drastically.

In the absence of a ‘supply manager’, markets today require physical shutdowns to move back into equilibrium. For this to occur, prices needed to move significantly lower, from incentive levels at around USD 85 per barrel to cash cost pricing (mid-USD 40s).

The role of OPEC

Central to the outlook for the oil price is understanding the traditional role played by OPEC (Saudi Arabia in particular) and why that appears to have changed.

As you can see from exhibit 1, the OPEC producers sit at the bottom end of the cost curve, with the marginal price being set on the far right by expensive deep water and oil sands projects. These types of projects typically require a far higher oil price to justify investment (USD 80-90 vs. USD 10-20) because the upfront capital expenditure is greater. To put it simplistically, consider the costs of installing a huge steel oil platform in 3000-metre deep water compared to drilling a conventional well on land.

In such a world, the revenue maximising strategy for OPEC in the event of a temporary surplus is to reduce volumes of output. This will hit revenues because less oil is sold, but the outcome is less bad than if prices drop to cash costs (i.e. if they halve in price).

When we have seen such behaviour before, the brunt of the volume reduction has been taken by Saudi Arabia as opposed to OPEC as a whole, with countries like Libya, Nigeria and Venezuela tending to be more reticent. This makes the Saudi Arabian incentive structure worth analysing in isolation.

With the advent of shale oil, there has been a clear increase in the opportunity set for oil producers with a large addition of a global resource which is economically viable at around USD 60 per barrel (see Exhibit 1; the large increase in shale resource access is shown in Exhibit 4).

Exhibit 4: ‘Opportunity set’ – addition to known oil resources

Chart 4

Source: Goldman Sachs, BNPP IP, data up to 2013

With that in mind, were Saudi Arabia to try to cut, say, by 1 million barrels a day to protect a USD 90 oil price, it would do little to stem the growth of shale and thus would necessitate further production cuts in the future.

Given the scale of the global resource in place and the potential growth rate of future production, such a policy would ultimately lead to volume reductions that would outweigh the benefit of a higher oil price to the kingdom in the long run.

In other words, because the incentive price has shifted from deep water projects/oil sands projects to US onshore output, the optimal revenue-maximising strategy for Saudi Arabia has changed from controlling prices to controlling volumes.

Where do we go from here?

With oil currently trading not far off cash costs, the scope for downside would appear modest, although it is worth bearing in mind that there can be a lag between changes in production and movements in the oil price.

As we move through 2015, the physical surplus should continue to build as (deep water) projects with longer lead times come into production and shorter term shale growth continues because of factors such as hedging pre-drilled well inventory.

However, with demand growth at about 1 million barrels per year this surplus should not last long. As we move into 2016 we expect that markets should begin to move back into deficit and prices should start to revert gradually to a level incentivising new production.

In our view, the resource additions from shale plays over recent years can more than satisfy future demand for the foreseeable future and consequently even in a bullish scenario we are looking at a rebound which should be capped at around USD 65.

But two factors are crucial for this eventuality to materialise: Firstly, continued geopolitical difficulty in Libya and Iran (where there are a potential two million bpd which could come to the market) and secondly, Saudi Arabia not choosing to increase production. Were either of these cases to occur we would be dealing with a far more prolonged period of weakness.


We expect oil prices to be capped at c.USD 55 (for a barrel of WTI) for the first half of 2015. Once physical markets begin tightening in 2016 we anticipate prices starting to normalise towards their longer-run incentive price level, which we see at around USD 65. However, any price normalisation will likely be gradual considering the by-then large inventory overhang from the 2014/15 episode.

Additionally, in consequence of today’s excess supply, prices need to incentivise storage, which results in a large negative roll-yield for long-oil investors. Given this, we believe it is also too early to build strategic long oil exposure.

[1] A stripper well is an oil well that is nearing the end of its econo-mically useful life. US stripper production was c.950 k bpd in 2009.
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