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A refined line

Downstream operations came to the rescue of the large integrated oil and gas stocks in the last three years. But could they soon become a drag?
March 8, 2018

Time, now, for a moment of self-criticism. In the last couple of years, there's been an inherent bias within the IC’s coverage of the so-called “vertically integrated” oil groups, as a brief scan through the archives reveals. We, by which 'we' mean this writer, has tended to focus on upstream operations – that is, the business of finding and producing hydrocarbons – as opposed to the downstream (the refining and marketing of those hydrocarbons). A preoccupation with rigs over distillation columns and refineries, if you will. Nostra (well, mea) culpa.

But how do we explain this, given downstream earnings account for the clear majority of revenues? For one, the per-barrel break-even price – one of the clearest financial metrics for charting the health of sector earnings – is most clearly understood at the wellhead. And leverage to these prices – in the shape of the margin made on extraction – is one of the big reasons why investors back oil and gas companies. It also means upstream profits and losses have a greater impact on the group’s bottom line.

Second, we can reliably assume that if Royal Dutch Shell’s (RDSB) upstream division is making money, then its refining operations are also contributing to earnings. The basic function of its oil products division is to turn crude into more profitable fuels, for which there are broad markets. It makes sense, therefore, that when Brent crude dropped below $100 (£71.90) a barrel after 2014, revenues in upstream, chemicals and downstream divisions all declined.

But refining margins aren’t the same thing as netbacks, and during a challenging period in which crude prices and market share have been fundamentally reset, downstream operations did exactly what they were designed to do: provide a hedge to a battered upstream. In the event, the supermajors’ enormous refining, marketing and chemicals divisions actually excelled, as margins increased despite the fall in overall sales prices. As the chart shows, the downstream operations of Shell, BP, Exxon and Chevron collectively grew their contribution to earnings in absolute and relative terms in 2015 and 2016, despite a fall in these business’s top lines.

As the International Energy Agency (IEA) and others have suggested, it is questionable whether the next four years will provide as much of a buffer. That should be of concern to investors in integrated stocks, given the widespread predictions that oil prices will remain range bound for the rest of the decade. So what support can refining margins offer the bottom line? And will markets continue to view the vertically integrated model as a worthwhile hedge?

Since oil prices ‘reset’, the consensus has been strongly in favour of the downstream. Without it, the majors’ cherished dividends would have been rendered unsustainable.

It wasn’t always this way. In April 2016, BP (BP.) chief executive Bob Dudley was facing a shareholder revolt over his pay packet and the biggest downturn in oil prices in three decades. Yet he could still reach for one source of solace. “Not so long ago I used to hear a lot of advice about how we should separate out our downstream business and sell it off,” he told investors at the group’s annual meeting. “I don’t hear that so much anymore.”

The arguments in favour of disposing downstream assets were twofold: that the high costs associated with maintaining downstream assets outweigh the profit hedge, and that physical integration of operations (using products in downstream operations) was less material, and thus a drain on the sector’s market valuation premium relative to other blue chips.

Amnesiac as it may sound, the debate could reignite. Indeed, in the context of the last three years, fourth-quarter results for the large integrated stocks’ refining businesses were underwhelming. Shell’s refining and marketing profit of $1.4bn fell short of analyst forecasts, and was down both quarter on quarter and year on year. The trend was in evidence at both ExxonMobil (US:XOM) and Chevron (US:CVX), so too BP, where a fourth-quarter dip in downstream earnings from $2.3bn to $1.5bn took the shine off an otherwise strong performance from its refining operations.

In fact, BP calculated that fourth-quarter refining margins fell 12 per cent to $14.40, as the table shows. And as Shell pointed out, margins fared particularly poorly in the period on the US Gulf Coast, falling from $13.04 to $8.59 per barrel. This was partly due to the first year-on-year rise in crude prices since 2012, which led to the inverse of the effect seen in 2015 and 2016.

Refining Marker Margins ($/bbl)

1Q/2017

2Q/2017

3Q/2017

4Q/2017

1Q/2018 to date

US North West

15.9

20.5

23.1

15.7

13.2

US Midwest

11.7

14.8

19.8

21

13.5

Northwest Europe

10.4

11.9

13.5

11.1

10.1

Mediterranean

9.7

10.4

12

9.6

9.1

Australia

12.9

12.9

13.7

12.2

11.6

Global Refining Marker Margin*

11.7

13.8

16.3

14.4

11.6

Source: BP, third parties. *Global margin is a generic composite indicator.

In its latest five-year global outlook report, the IEA gives several reasons to believe that this bearish outlook might persist, despite the absorption of surplus refined product at the end of 2017. First, excess global refining capacity is set to increase at a faster rate than the demand for refined products. By 2023, the Paris-based group calculates that newly-built refineries will have added 7.7m barrels per day (mmb/d) to total capacity, compared with a 5.4mmb/d uptick in throughput. This will put pressure on utilisation rates, particularly in southeast Asia, Europe and North America, where the supermajors are especially active.

Greater capacity means stronger competition for throughput, lower utilisation rates and greater pressure on refining margins. Added to this, China and the Middle East are set to increase their exports of refined products, potentially adding to pressure on the non-NOC integrated players. Investing in refineries therefore looks like one of the riskier bets available to big oil executives, even if high recent utilisation rates in the US and Europe have provided a natural incentive to add to capacity. In light of this, ExxonMobil’s decision to increase capacity at its giant Beaumont refinery by 350,000 barrels per day by 2023 could result in a fairly weak return on capital – assuming margins do in fact contract and investments aren’t passed over elsewhere.