“Preparing for the recovery”… Whatever…

The IEA has recently published it’s new World Energy Review and if you have been reading this blog this comment will come as no surprise:

One notable trend concerns the relationship between oil prices and upstream costs. In the past, there has been a roughly linear relationship between upstream costs and oil prices. When price spiked, so did costs, and vice versa. What we are noting now is a decoupling. While prices have more than doubled since 2016, global upstream costs have remained substantially flat and for 2018 we estimate those increasing very modestly, by just 3%. Companies appear to have learned to do more with less.

Too many business models in the offshore supply chain are simply ignoring this. If you are going long on Borr Drilling shares (for example), as anything other than a momentum trade, then you need to look at data driven forecasts like this, which in statistical terms are called a structural break. Look at the cost deflator in the graph above! In an industry with high fixed costs (both original and operating) that is a straight financial gain for E&P companies and with the volatility in the oil prices they will not give that up easily… and in a world of oversupply they won’t have to.

The future will be different. Some vast market snapback where the Deamnd Fairy appears, and everyone brave enough to have paid OpEx in the offshore supply chain has found a clever get rich quick scheme, is an extremely unlikely event.

More data points like this should make you think as well:

IEA Source.png

Yes, I get the volume in absolute terms is growing, but it is change at the margin that defines industry profitability.

There is still too much liquidity and too many business plans talking as if a return to 2013/14 is a certainty when in reality such a scenario would be an outlier.

The current oil price…

“You cannot improve a signal if you do not know what it signals”.

Fredrich Hayek

Trump 1 July.JPG

The oil price is hitting new highs but I don’t think this is going to have a dramatic effect on offshore for the next couple of years if at all. This is a supply constraint, particularly in relation to the Iran sanctions, and therefore this needs to resolved through the price mechanism in the short-term as all other swing producers are maxed out in terms of capacity as Libya and Venezeula also encounter problems.

This is a completely different investment narrative to the 2008-2014 boom. Then the rising price was viewed by the market as a reponse to rising Asian demand and the costs of developing new marginal sources of supply. The core of the rising price story was a demand driven boom.

No rational E&P company increases investments in 10-20 year fields in response to a price fluctuation with clear geo-political roots that could all be resolved in a relatively short period of time. By the time the field is built and delivered the political situation could have been resolved and then  the extra capacity will just lower the price. I could be wrong but I find it incomprehensible that Iran can be kept out of the international oil market forever. For these sort of changes in supply the changes in supply and demand need to be met with the pricing mechanism.  Some short-term changes in operating expenditure to boost production may become viable but not a wholesale commissioning of new fields.

As the Brookings Institute notes Trump seems to be pushing for regime change as the goal in Iran and the Saudis may have promised air cover with 2m b/d (and the strong administration links to Israel will also be coming into play here). This is a short term issue and maybe if the price gets too high here, and no one really believes the Saudi Arabia can come up with that sort of number in the short-term, then that will cause a change in policy. But I doubt it… Price will be the relief valve for what extra production OPEC cannot cover in the short-term.

As I have mentioned here before I think the link between the oil price and the demand for offshore services has altered fundamentally. Simply claiming now that a supply driven change will automatically be positive for offshore in a substative way is I think wrong and does not account for the difference between a demand driven expansion and a supply constricted shortage.

The wrong side of history…

“Until an hour before the Devil fell, God thought him beautiful in Heaven.” …

The Crucible, Arthur Miller

 

On the IHS Markit projection, by 2023 the Permian is likely to be producing an additional 3m b/d of oil, along with an extra 15 bcf of gas. For the US economy this news is positive. America will have a secure source of supply that, through its production, distribution and consumption, will generate significant economic activity across the country.

The volumes involved will further reduce the unit of production, probably to below $25 a barrel. The study estimates the total investment needed to deliver the new supplies will be some $300bn. For the global oil market the effect will be dramatic. The US will become a significant exporter. The IHS Markit paper suggests that by 2023 the country will be exporting around 4m barrels a day. That will absorb much of the expected growth in demand. [Emphasis added].

Nick Butler, Financial Times, June 25, 2018

 

For one thing, customers have an unfortunate habit of asking about the financial future. Now, if you do someone the single honor of asking him a difficult question, you may be assured that you will get a detailed answer. Rarely will it be the most difficult of all answers – “I don’t know.”

Where are the Customers’ Yachts? 

Fred Schwed

In case you missed it another major pipeline looks certain to go ahead in the Permian by 2020 (in addition of course to the Exxon Mobil 1m b/d). If the 30″ version is selected then 675k barrels a day will be added in export capacity to the port at Corpus Christi, where a major upgrade is also taking place that will allow significantly larger tankers into the region:

Oil export capacity from the Corpus Christi area is expected to rise to 3.3 million bpd by 2021 from 1.3 million bpd this year, keeping its rank as the top oil export port, according to energy research firm Wood Mackenzie.

In fact if you believe Pioneer Natural Resources (on S&P Platts) then Permian pipeline capacity will double by 2020 (to 3.5m b/d) and the US production will reach 15m b/d by 2028. The graphic at the top of the page highlights that top Permian wells are profitable at $22 per barrel. There is a good point on the interview where the CEO of Pioneer points out in 2015 the dominant narrative was shale would go bankrupt and in fact there has been a rebound.

This continuous process of capital deepening, infratsructure upgrades, and productivity improvements has driven the recovery of the US shale industry and has devastated the offshore industry. There is a link: it is not all inventory and reserve rundown. Offshore used to have to run at very high utilisation in order to work and without it the economic model is broken. No other economy in the world excels at this kind of constant, small-scale, mass production improvement like the American economy. Once a product can be mass produced at scale the ability of the US economy to drive down per unit production costs is unmatched.

At the moment there is a boom in the Permian and Eagle Ford basins: wages are high and there are delays and bottlenecks (I read a story last week of a power company demanding 40k to put in one power pole) but this capital deepening will alleviate some of these issues in the short-term. Trucks will be replaced with pipelines etc, a new generation of high spec rigs in the  offing. Deliver, review, improve. Always with a focus on productivity and efficiency. Shale is a process of horsepower and capital and those are two attributes the US economy is preternaturally endowed with. Each incremental pipeline becomes less important in a relative sense so the investment bar is lower. Slowly but surely unit costs get lower every year. It is a relentless and predictable process.

That is the competition for offshore for capital at the margin: an industry improving its efficiency and cost curve with every month that passes. And the solutions to constraint problems in the Permian are on a timescale measured in months while investments in offshore take years to realise.  Offshore offers huge advatages over shale in terms of high volume flow rates and low per barrel lift costs but it is a long term CapEx high industry and not suited to production of marginal volumes. There is every likelihood it is used as a baseload output in years to come while shale supplies marginal demand. This is a massive secular change for offshore and will fundamentally alter the demand curve to a lower level. The clear evidence of this seems to be causing a degree of cognitive dissonance in the offshore industry where any other outcome that a return to the past is discounted.

To just focus the mind: if offshore were to improve productivty by 3% per annum for three years- which is considerably slower than the productivity improvement in shale – day rates for offshore assets in 3 years would need to be at c.92% of current levels per unit of output (i.e. a 8% reduction [1/1.03^3]). Not all of this is going to be possible in offshore execution terms given the aset base, some of this will come from equipment suppliers who are manufacturers and subject to scale economies reducing costs, but this is the challenge for offshore bounded by Bamoul constraints. There are limits to the volumes that can be produced by shale but they have constantly exceeded market expectations and they have eaten a meaningful share of global oil output and this will not change only increase.

As the graphic below shows this is a supply side revolution as demand for the underlying commodity has increased consistently since 2006:

Global Oil Demand 2006 to 2018F

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So the only possible explanation for the continuing drop in the utilisation of offshore assets is that the demand has fallen for their use relative to the global demand for the underlying commodity they help produce.  I accept that may look tautological but we just need to clear that point out early.

I have been on before about how I don’t think a quick recovery is likely for the offshore market for those long on offshore delivery assets only (the tier one SURF contractors are different as their returns are driven by engineering as well as asset leverage). I can’t see how an industry like the shale can develop in parallel with a “snap back” in offshore, particularly when the larger E&P companies have been consistent and vocal about limiting CapEx.

The reason jack-up companies are like offshore supply companies, and not SURF contractors, is that they take no project risk. An oil company doesn’t handover well risk to a drilling contractor (as Macondo showed). Shallow water drilling contractors are the AHTS and PSV of drilling: you get a day rate and that is the only value we expect you to provide. It is an asset return and utilisation gig completely different from SURF contracting. And yet against this background there is a bubble developing in the jack-up market seemingly unsupported by any fundamental demand side recovery. I am not alone here: McKinsey forecast jack-up demand to rise 2% per annum to 2030 (about a 10% growth in market size over the next five years).

Bassoe on the other hand are forecasting that day rates will double in the jack-up market in five years, which equates to a 15% compound average growth rate.  I realise this narrative is one everyone wants to hear, you can almost hear the sighs of relief in New York and London as the hedge funds say “finally someone has found a way to make money in offshore and profit from the downturn”. And as the bankers stuff their best hedge fund clients full of these jack-up companies stock this is the meme they need as well. At least in this day and age the investors have better yachts than the bankers.

Yet the entire jack-up market thesis seems to rest on the accepted market narrative of scrapping and therefore higher utilisation. As Bassoe state:

If 85% jackup utilization seems relatively certain, then a doubling of dayrates is too.

Certain is a strong word about the future… As if the entire E&P supply chain will benignly accept day rates increasing 15% Y-O-Y from every single market participant without worrying about it…

Ensco is a good place to look because it also considers itself a leader in premium jack-ups. Ensco has exactly the same business model as Borr and Shelf (indeed it is focusing on exactly the same market segment in jack-ups): raise a ton of money, go long on premium assets and wait for the market to recover… Ensco’s recently filed 10K shows how well this jack-up recovery is going:

Ensco q1 2018.png

Oh hold on it doesn’t show that at all! Instead it shows the jack-up business revenue declined 17% Q1 18 versus Q1 17. Awkward… So like everyone else here is the crunch of the “market must come back” narrative: Scrapping.

Ensco jackup fleet forecast.png

The problem with this argument is the scale of the scrapping required in the red bars (not to mention the assumptions on China). If that slows and/or the market growth doesn’t quite come then the obvious downside is that there are too many jack-ups for the amount of work around. Somewhere between 2% and 15% compound per annum leaves a lot of room for error.

When your revenue figures drop 17% on the previous year management in most normal companies, but especially those with a very high fixed cost base and a disposable inventory base (i.e. days for sale), tells the sales reps to cut the price and win market share. And that is exactly what will happen here. In fact far more accurate than forecasting the market is an iron law of economics that in an industry with excess capacity and high fixed costs firms will compete on price for market share. Investors going long on jack-ups are making a very complicated bet that the market growth will outpace scrapping in a way it hasn’t done in the past despite E&P companies being under huge pressure to keep per unit production costs low.

On the point of the age of the jack-up fleet: this is clearly valid to a degree. But as anyone who has negotiated with an NOC in places in South East Asia and Africa can tell you all this talk of new and safe over price is Hocus Pocus. Otherwise in the greatest down market around none of these units would be working or getting new work and that clearly isn’t the case.

In fact in many manufacturing businesses old machines, fully depreciated and therefore providing only positive cash flow to the P&L, are highly prized if they are reliable. There is no evidence that this will not happen in offshore and plenty of counter-examples showing that oil companies will take cheaper older assets. The best example is Standard Drilling: bringing 15 year old PSVs back to the North Sea that were originally DPI, and getting decent summer utilisation (day rates are another issue but for obvious reasons). Eventually as the munificence of an industry declines the bean-counters overpower the engineers and this is what I believe will happen here, there is plenty of evidence of it happening in offshore at the moment. Every single contracts manager in offshore has had a ridiculous conversation with an E&P company along the lines of: “we want a brand new DP III DSV, 120m x 23, 200t crane, SPS compliant, and build year no later than 2014 and it’s a global standard… and we want to pay 30k a day”… and then they go for the 30k a day option which is nothing like the tender spec.

The reason is this: North Sea E&P companies are competing against shale for scarce capital resources and they need to drive costs out of the supply chain constantly. Offshore has dropped its costs in a large part because the equity in many assets and companies has been wiped out, that is not sustainable, but what is really unlikely to happen here is a whole pile of asset managers wake up simultaneously at E&P companies over the next three years and tell people to wholesale scrap units knowing it will increase their per barrel recovery costs while watching shale producers test new productivity levels.

There may well be a gradual process on a unit-by-unit basis, a cost benefit analysis as the result of some pre-survey work or a reports from a offshore crew that the unit isn’t safe, but not suddenly 30 or 40 units a year, and if does happen too quickly and prices rise then the E&P companies will revert to older units to cap costs. Fleet replacement will be a gradual process and some operators will be so keen to save money that they will let some older units be upgraded because it will have a lower long term day rate than a newer unit because they get that to continue to have capital allocated they need to drive their costs down.

The investment bubble in jack-ups is centred on Borr Drilling and Shelf Drilling. These companies have no ability or intention to pay dividends for the next few years. Credit to them: raising that sort of money is not easy and if the market is open you should take the money. Their strategy, in an industry that patently needs less capital to help rebalance, is to add more and wait for a recovery. Place everything on 18 red at the casino. Wait for higher prices and utilisation than everyone else despite doing exactly the same thing (just better). And that’s fine it’s private money, and it might work. But economic theory I would argue suggests it is extremely unlikely, and it will be a statistical outlier if it does. Five years ago the US shale industry was producing minimal amounts and the dominant thought was they required $100 oil to work so think how different the world will be by the time these companies have any hope of returning cash to investors?

Forecasts are hardly ever right, not for lack of effort but the inability to take into account the sheer number of random variables, the epsilon, in any social process. Forecasts that a segment of the offshore market will double given the headwinds raging against it should probably be viewed as bold, a starting point for debate rather than a base case for investments. Having picked 9 of the last 0 housing crashes you should also realise that while my arguments will eventually be proven right the timing of them can be wildly inaccurate as well.

Reserves Rise Rapidly…

I have writtent about reserve replacement ratio figures before (i.e. here). It has become part of the accepted meme in offshore for why there must be a recovery. The above IEA data just released categorically shows this isn’t really an issue at the moment and there are now numerous data points that for large companies in particular investors are happy for the reserves figures to drop below historical averages.

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I am writing a longer piece on momentum, herding, and the jack-up market where I think people are getting a little carried away. I note that this isn’t unique to the oil and gas segment with the FT having a good article on Norwegian this weekend. Like some jack-up companies today Norwegian took an outsized bet on a market coming about (low cost international with a new business model), unfortunately for them it just hasn’t. Norwegian benefited from aircraft manufacturers wanting to sell planes that allowed them to embed huge amounts of leverage in their financial structure that would not be possible in a “normal” market. As the Bernstein analyst says:

“If you’re a holder, you need to sell. If you can short the stock, short the stock.” A second analyst, who did not want to be named, is blunter: Norwegian could “go bust in the autumn”.

Stock markets are known to be irrational, momentum strategies in particular are known to exist at certain points in time but to be transitory in  nature. Norwegian serves as a warning to anyone following exactly the same strategy in oil and gas.

However, nothing excites markets more than forecasts of markets doubling in five years (a magical number in  finance which equates to a 15% compaound annual growth rate over five years (1.15^5*)) forgetting that earnings discounted that far out at a discount rate that reflects the risk could easily absorb any rational return calculations.

But back to my point here: if reserves are your argument for increased offshore activity I think you need a new one.

*Number updated for a typo in the original version.

Time for plan B…

A somewhat ambitiously titled article in the FT seemed to have something for everyone: looking for any excuse to claim the impending supply shortage? Check.  And for the sceptics? Check. To save you reading ‘The Big Read’ I’ll give you a quick synopsis: the reporter spoke to a load of people (mainly analysts) who said there will be a supply crunch but didn’t know when, and then spoke to another bunch of people (who actually make the investments) and they said they don’t think there will be.

The fact is that oil will be a substantial part of the energy mix for a very long time. How we extract it and the relative costs of doing so are far more interesting questions. The E&P companies will be substantial businesses for a long time to come no matter how alarmist some warnings maybe.

But the article does mention the mythical $100 per barrel… just not a timeframe… in fact if you are looking for comfort for when this supply crunch will occur the only person prepared to put a timescale on it is ex-BP CEO Tony Heywood, and you are unlikely to get much comfort from this:

“I don’t think the supermajors really believe the long-term story of peak demand,” Mr Hayward told the Financial Times last week. “Looking at the trajectory, we’re more likely to have a supply crunch in the early 2020s.”

If you really believed in the supply crunch I can’t work out why you wouldn’t sell your house and just go long on Exxon Mobil? According to this article on Bloomberg they are staying as a pure oil and gas supermajor and being punished by the stockmarket for it. Buy their undervalued shares and when the supply crunch comes all their reserves are worth the market price and they have production capacity? And in  the meantime you collect the dividend?

The alternative in the offshore world appears to be buying investments in highly speculative asset companies with no order book that are relying entirely on a macro recovery for their plans to work. At this point in the cycle, and without some clear indication of when any of these plans can return actual cash to the investors, the only thing certain is that they supply side still has a lot of adjustment to go. The big contractors are starting to pull away from the small operators because a) they do the large developments currently in vogue, b) scale has economic advantages in an era of low utilisation, and c) why use a small company where your prepaid engineering work is effectively an unsecured creditor? Expect the flight to quality to continue in the project market.

Frankly if you are long floating assets you simply cannot disregard comments like this from one of the biggest CapEx spenders in the world:

“We’re becoming more efficient at how we deploy capital,” Mr Gilvary says. He adds that BP and other energy groups are ploughing a middle road: raising oil production by using technology to sweat more barrels out of existing fields, while also funnelling smaller amounts of capital into so-called short-cycle projects such as US shale.

BP of course continue to deliver mega-projects where they think they have ‘advantaged’ oil. They just expect to pay less for it:

BP Unit costs.png

Reintroducing cost inflation into the industry will be harder than any previous cyclical upturn is my bet.

More of the same…?

There are two reasons why the world has lost confidence in forecasts. First: the record is awful. Remember the predictions of oil at $200 a barrel or the view that nuclear energy would be so cheap that no one would bother to meter its use?

The second reason is that events, especially around technology, are moving so rapidly that it is difficult to keep up with what is happening already, never mind what could come next. Artificial intelligence, energy storage and, at a very different level, the spread of religious fundamentalism are all potential game changers in the energy market. Yet predictions of how and when their influence will be felt are no more than guesses.

Nick Butler

Professor and chair of the Kings Policy Institute at Kings College London

GS oil price 18 June 19.JPG

Goldman Sachs, 18 June, 2018

In our Lower 48 business we co-developed a pad optimisation mathematical model with a Silicon valley start-up. This is the first time it has been applied in the Oil and Gas industry. When initially deployed on 180 wells and five pads, it reduced emissions by 74%, increased production by 20%, and reduced costs by 22%.

Lamar Mackay, BP Upstream CEO

 

The graph at the top is the IEA’s forecast for the oil price in 2019. I don’t get caught up on forecasts because for obvious statistical reasons they have a low probability of being correct, but they interesting in that they reflect the current “dominant logic” or investment narrative.

Brent crude averaged $54 per barrel in 2017 so obviously a near 30% price increase is good news for the beleagured offshore industry. But I am struggling to see a breakout here which isn’t just more of the same where a little incremental revenue gets added each year? At the moment volume also appears to be increasing more than value in the offshore industry (i..e companies are doing more for less).

There is optimism in the jack-up market though… investors are throwing money at jack-up companies that are promising not to return money in dividends (or indeed any form of capital repayment) and build market share in a highly fragmented industry. I struggle to see how these companies can in effect be adding capital to an industry when the majority of their customers are trying to reduce capital intensity? It is an odd dynamic where they are buying jack-ups for 30% less than cost despite the fact that in the old days utilisation used to be between 90-100% and now it is accepted it is much lower. A jack-up with only 8 months work is worth more than 30% less than one with 12 months work given the high fixed costs and the same day rate… and yet day rates are still under pressure and still the deliveries keep coming.

More later when I have more time but I think this is becoming an irrational market if demand stays at these sorts of levels. The ability of E&P companies to force time risk back to asset owners marks a fundamentally different industry in terms of structural profitability potential to one that existed in the past. I get scrapping reduces net units in the market but with the fleet utilisation of around 50% there is a lot to go and the option costs of these companies without significant work is very high in cash terms…

Anyway these forecasts are important in that about now E&P companies are starting to set budgets for 2019 plans. Based on the sort of forecasts you can expect only a marginal increase in spending and in offshore that isn’t what a lot of business plans want or need.

Oil as a declining industry…

Like all good Op-Eds (and blogs) this one in the FT started yesterday with a big headline and with some punchy quotes:

The time to stop investing is not today. But that point is coming. The industry needs to be clear that its future is one of long-term decline — whilst returning increasing sums of cash to investors. There is a possibility that the industry over-invests as we reach that point of peak demand, leaving an oversupply that persists for a long time. Fighting for market share in a declining market would be even worse.

Everything in life is relative (well if you are a post-modernist anyway) and the authors are not saying to stop investing tomorrow or that oil is dead: merely ex-growth as an industry.  The message is about E&P companies not having a good record at investing in alternative energy sources so encouraging them to return the cash to fund managers (who do apparently?).

We think oil companies can have a positive part to play in our future world of energy — as a cash generating engine that can be used to power the transition when the time comes, and we urge the industry to make a clear commitment to this future.

You can dismiss it as another view that will simply ensure that prices are higher in the future, I guess the question then becomes how far and how high? Or you can take the views seriously as the representatives of one of the UK’s largest fund managers and realise that it is part of a wider secular shift in thinking about business models for E&P companies that require less CapEx and less redundant capacity. I think it just shows how much pressure CFOs/Directors are under to return cash to shareholders all the time and how much harder it is for smaller E&P companies with good project ideas to raise money.

Regardless or your view this is becoming a popular one amongst the actual owners of some companies so it is worth not writing off indiscriminately. The investment narrative isn’t all “growth at any cost”, or future production volumes, which is a marked shift from previous periods where statements like “all the easy oil has gone” doiminated.

In a good interview here Spencer Dale, BP Chief Economist highlighted that

Because of natural decline, there is going to be a huge need for investments to keep supply at pace with demand, even if oil demand were to peak relatively soon.

“For a company like BP, that has a key role in our strategy. Continue to invest in oil, because the world will need that investment, but make sure to invest only in low cost, advantaged oil to make sure that we are robust for this more competitive environment that we think is going to emerge over the next ten to fifteen years.”

That strikes me a very different dynamic to previous eras and will have a huge impact on E&P project developments which are also consistent with the shareholder wishes highlighted above.