E&P versus offshore strategy plans… Not what you think?

Last week ExxonMobil released its analyst day presentation. It has a number of interesting things, but I wanted to highlight the fact that although it feels like E&P companies are back making real money, which they are, it may not feel like that to them. And as this article on Bloomberg makes clear investors in these companies want management to keep the lid on CapEx, which is one of the cash flows they really can control:

Exxon argues it has a formidable set of projects, pointing to such goodies as offshore Guyana discoveries, as well as the Permian basin. The problem is that investors have seen this story before, and quite recently, with the oil majors. And while Exxon’s reputation might once have enabled it to simply be trusted to deliver, that is no longer the case.

Here is a Bloomberg shot showing you what would have happened had you purchased 1000 ExxonMobil shares in 2013 and sold at the end of 2017 (about when plans were probably being agreed):


You were down fractionally in the share price and up overall marginally only after reinvesting dividends. So the Directors are probably not coming under massive pressure to throw more money at production when 4 years after the price slump the owners of the ExxonMobil are trading below their 2013 entry cost (or fund market value). This is very oversimplified, but I make the point only because it has become an article of faith amongst some in the offshore space that E&P companies are verging on the irrational by not increasing offshore project spend when it is far from clear they are, or that they face pressure to do so.

Which is why you end up with a slide like this from a company that has just made some huge offshore discoveries:

Disciplined value.png

ExxonMobil focuses on Brazil and Guyana in terms of offshore development. I think the larger E&P companies switching to larger developments only offshore continues to mark a real shift in the market because the smaller companies just don’t have access to the development funding they used to for smaller fields.

I thought this was interesting:

XOM Guyana.png

Versus shale:

XOM tight oit.png

ExxonMobil appears to be implying shale has a lower breakeven pricing at $35 to get to a great than 10% return? And as always productivity is increasing:

XOM productivity increase.png

The other thing that struck me about the presentation was just how many investment opportunities management have across the portfolio, and they are increasing CapEx across the forecast period from USD 24bn to USD 30bn, but it is clear that downstream and other activities are also important. Investors want growth but maybe some at lower volatility that a fluctuating oil price offers, and as this graph shows ExxonMobil will make money at USD 60 ppb oil, but not ridiculous amounts.

XOM Fundamental.png

Obviously XOM is a leveraged bet on the price of oil increasing. But at the moment the upstream managers probably feel they have a free option on the excess capacity in the offshore supply chain that means any rapid price increases can be met with shale and a slower commissioning pace of offshore fields. Also these larger discoveries allow greater flexibility to speed up infield developments at a lower cost and asset utilisation.

Bourbon Offshore recently released it’s Bourbon in Motion strategy which to my mind is one of the most honest assessments of the scale of the challenge facing offshore companies I have seen. I think Bourbon are well worth listening to because I cannot think of another company that has played the capital markets as well as they have in financing their operations. Here in 3 simple points is the problem every offshore company faces:

3 issues.png

And it was really nice to see it wasn’t followed by a slide which said “but we are doing lots of tendering”.

A little history is required: In 2008  Bourbon had €1.3bn in debt and was focusing almost exclusively offshore. The annual report for that year described the returns in the offshore business as “exceptional”, and like all good companies it took this as a price signal to invest and grow the business further. Bourbon did this, because as the financing market was so flush it could borrow a lot of money, by 2013 debt had increased by €1bn to reach €2.2bn and the Directors were so confident about the business they proposed a 34% increase in the dividend.

In 2013 and 2014, taking advantge of the exceptional sentiment in the market Bourbon sold, and then leased back, vessels worth €1.65bn to Standard Chartered and ICBC which also allowed them to write up the value of the rest of the fleet by €900m in value. It’s hard to overstate how good the timing of this transaction was, timed literally to perfection, as the vessel market peaked in value they got two banks to pay not only top dollar for the assets but lease them back at less than 11% per annum. I doubt if sold on the open market here these now commodity vessels would fetch a third of that.

I am not implying Bourbon knew this would happen, what I am saying is they worked out that perhaps this was as good as it was going to get in the industry and they should bank what they could and take some (more) money off the table for their shareholders. As a management team it made them look very smart.

So when Bourbon tell you things are grim I think it comes with a degree of credibility few can match. Particularly when backed by some solid data:

The worst crisis ever

Which we all know by now. As I have said here repeatedly understanding that CapEx expenditure is what drives utilisation at the margin, and therefore overall fleet profitability, is crucial. And the reason I used ExxonMobil above was to show that this CapEx number, which I call “The Demand Fairy”, is unlikely to miraculously change in the short-term.

Offshore will still be an important part of the energy mix, but the growth of shale, as the left hand graph below makes clear, is having a huge impact on vessel utilisation and therefore industry profitability:

Bourbon Offshore production.png

The region reserved for shale is an area 3 or 4 years ago most people investing in offshore would have believed their assets would be servicing. And when you rely on 75-80% utilisation just to break even that in effect changes the whole economics of the industry, because if it knocks even 10% utilisation back across the fleet everyone is struggling to break even on their assets.

The right hand graph shows the enormous drop in CapEx. The fact that more projects are being sanctioned but the spend is lower just highlights what company results are showing: the volume of work has increased slightly this year but the value being paid for it has not (or reduced in some cases). This is likely to be a structural feature of the industry going forward that previous margin levels will simply not recover.

Like everyone else Bourbon is making a play to drive down the cost of operation of its commodity assets and add more value to the value of its subsea assets through moving up the value chain. Across the industry an entire species of contractor that used to make a good living by supporting larger contractors now aims to do more projects directly with E&P companies. Bourbon, like others, will likely win some market share, but they will do this by competing on price and driving industry margins down overall. For Bourbon it will still feel like more revenue than running the vessel alone, and in the long run it maybe, but grow to big and the larger contractors will be unlikely to charter your vessels. That slow increase in the blue bar on the graph is a result of all this extra capacity coming to market on the contractor side and why good Bus Dev staff in the industry are still remarkably employable.

It’s a post for another day the problem for offshore demand in shallow water, where projects could be done by flexibles and a vessel-of-opportunity, is that the smaller companies who used to do these projects simply have no access to the capital markets. Capital markets prefer smaller projects to be shale-based now where the cash-flow cycle is shorter. Think of the last time an Ithaca Athena development was commissioned on the UKCS?

Obviously the E&P companies are doing better than the offshore supply chain, the point is that they are not doing so much better that things are likely to change immediately. Bourbon seems to realise the future may look a lot like the present on the demand side and adjusting its business model accordingly.

(Hat-tip: SE).


The shale productivity revolution in context…

“[W]e can see the computer age everywhere but in the productivity statistics”

Robert Solow


A great article in the FT today (behind paywall) on the boom in shale being driven by productivity increases (a near facsimile earlier version appears here). Readers of this blog will notice a consistent theme, as Krugman said, “productivity may not be everything, but in the long run it’s nearly everything”. The importance of this is that the US is turning shale into a manufacturing industry, small incremental improvements day-in, day-out, that cummulatively dramatically lower overall per unit costs:

In 2015, shale oil producers on average used 3,300 tons of sand per well, according to Petronerds, a consultancy. By last year, that had almost doubled to 6,100 tons per well. Delivering that much sand to the well site can require 250 truck movements. Other techniques for shale production have also been refined to increase the amount of oil that can be extracted. Modern rigs can drill faster, further, and more accurately than their predecessors. The process of hydraulic fracturing is being split up into more “stages”, allowing effort to be focused more precisely on oil-bearing rocks.

Innovations using the latest computing and communications technology, including remote operations, are also starting to be used more widely. Schlumberger, the oilfield services group, says that in 2014, 13 per cent of jobs it worked on at US onshore wells were supported by technical experts watching from its Houston campus. By 2017, that was up to 31 per cent.

This coincided with the IEA forecasting that the US will become the world’s largest oil producer by 2023 (graph above). [It is well worth having a look at the 13 slides at the bottom of the page of the IEA link]. Investment remains depressed in all but tight oil and the comment at the bottom of this slide regarding offshore is telling:

IEA Upstream Spending.png

The IEA is worried:

that despite falling costs, additional investment will be needed to spur supply growth after 2020. The oil industry has yet to recover from an unprecedented two-year drop in investment in 2015-2016, and the IEA sees little-to-no increase in upstream spending outside of the United States in 2017 and 2018.

“The United States is set to put its stamp on global oil markets for the next five years,” said Dr. Fatih Birol, the IEA’s Executive Director. “But as we’ve highlighted repeatedly, the weak global investment picture remains a source of concern. More investments will be needed to make up for declining oil fields – the world needs to replace 3 mb/d of declines each year, the equivalent of the North Sea – while also meeting robust demand growth.”

The real questions here revolve around how much capacity is being replaced annually, and it is simply not true that 3mb/d are not being replaced at the moment. The producutivity improvements in shale above are part of the solution. Other questions are what sort of price increases would crimp demand? etc. There appears to be no change in investor expectations that they want E&P companies, certainly large ones, to reduce debt and increase shareholder payouts, and therefore capital projects will remain subdued. There is also a strong feeling in the investment community that reserves can be run down.

Without wishing to sound like a broken record the “Demand Fairy” isn’t saving anyone in offshore. Offshore needs to re-engineer it’s business model to compete. The IEA is clear that this weakness will be felt from 2020 onwards, so even if you accept their reasoning, that is a long time to keep burning OpEx if your business model cannot even breakeven in the current climate.

I view shale as a technological revolution and believe that no economy is better suited to maximising its potential. Perez defines the major economic technical revolutions since 1770 into five categories, and the US is dominant in the last three:

Tech Rev 1770 -2000s.png

Revolution is an overused word. But according to Perez’s definition, that I agree with, the shale industry is a Technological Revolution (TR):

Tech Rev Definition.png

This to me is the most interesting part of economic history, because while there are nuances the broad economic development of industrial patterns are really well understood. A classic article here compares the development of the computer industry to electric dynamo. Like shale it is a story of how US capital markets funded ambitious companies, vast economies of scale, manufacturing efficiency gains, and the slow initial diffusion of producitivity gains (think tight-oil 2007).

How long can this positive productivity feedback loop, where innovations throughout the system positively affect other inputs, continue? A long time I suspect. Shale may not be subject to the same volume effects as the PC industry but it still makes an interesting comparison (Allen):

Computers deflator.png

(For those who can’t remember logarithmic maths from school all the left hand bar of the top graph means is “this is a really big number… so big we have a formula to make it shorter”. And the bottom graph just means that even though the price dropped really quickly a lot of new features were added as well). This is a hallmark of the US economy and a manufacturing industry based on constant productivity improvements.

An earlier, and slightly different technical revolution, can be seen with the invention of Corliss Steam Engine,  which allowed America to break free from the constraints of water power in the 19th century (Rosenberg and Trajtenberg). Like shale this was an energy revolution, one that changed the structure of the US economy and allowed manufacturing and urbanization to begin in earnest. Corliss Steam Engine.png

Everytime I write about shale I want to write something about the incredible economic period of the 1930s: How US mass production techniques, a revolution in both managerial skill and capital formation, led to the creation of the economy that created Victory Ships and transformed the Ford factory at Willow Run (YouTube watch this, seriously) into the manufacturer of the B-24 (“the Liberator“), innovations that arguably changed the course of the WWII, and ultimately the post-war global economy. There are surprisingly (and disappointingly) few journal and web references to this, and all are about the mathematics of productivity, when this is really a story to be told at the company level. However, economic development is path dependent and these processes and learnings today are being applied in the shale basins every day, even if unwittingly. (For a broader read about what an incredible period the 1930s was in microeconomic terms this the best I have turned up so far).

So although I don’t understand the individual impact of every innovation listed on this slide I understand where they came from and the process driving this:

Nabors Rig.png

Once upon a time a PSV went for the low-to-mid USD 20ks a day. At the time of writing the BHGE rig count hit 800, the revolution therefore continues…

A market recovery? Not in the data…

Danish Ship Finance have just published their latest report. As usual it is thorough and measured, and frankly not uplifting if you are long on vessels or rigs. The graph above really covers a lot of things I have blogged about here, it’s all well and good coming up with graphs showing how offshore MUST get more investment, as if it were a divine economic law, but that isn’t what companies are ACTUALLY planning on spending.

Another great graph is this one:

DSV Charter Rates DSF.png

What the commentary in the report omits, and I think is very important, is the fact that the divers costs, which are c. £50k for a 15 man team, have not dropped. So for the vessel owner the rate hasn’t dropped 50% it has actually dropped 67% because the labour cost of the dive crew is fixed (again I have blogged about the Baumol effect here). This is probably more pronounced on DSVs than any other asset class but it is a real problem for offshore because the industry isn’t getting more productive (just cheaper which is different). Removing 67% of the revenue for any business is bad, in an industry that had binged on debt, as can be seen, it is beyond a disaster.

DSF also note that while spending on Subsea Production Systems is rising this because smaller step out developments are being done, which require less vessel days, than larger greenfield developments. Again I have discussed this before here.


Finally, it highlights again the scale of the pullback in offshore and why any recovery will not be a repeat of the past. The speed at which contractors are working through backlog is a real concern. Subsea 7 won work recently on the Johan Castberg field that was valued at c. USD 2.0 – 5.0m per well, a 75% decline from the peak. So even an increase in the volume of work awarded will not help the industry recover to previous levels.

Big Three Backlog.png

Subsea Contract Awards.png

This matters because offshore used so much leverage to purchase assets in the past. Now the companies revenues and profits are materially smaller and they are struggling to pay the banks back leading to a credit crisis in the industry. Debt is a fixed obligation that must be paid back for firms to have value and that is much harder to do when the industry is in a deflationary cycle. This is no different to a banking crisis without a central bank.  It is this credit crisis that when combined with the demand crisis makes this so serious. DVB Bank, a specialist lender to the sector, went bankrupt! Indeed I have discussed this many times and it is one my one recurring theme.

Last year probably was the low point in terms of demand. But as the first graph makes clear there is not a wave of investment coming here, just a long slow increase in spending.

Read the whole thing. Many business plans simply don’t reflect this reality yet. Not everyone will survive. 2018 promises to be another tough year for asset heavy companies.

The drawdown on offshore… My views on shale and offshore…

A friend asked me this week what my view on the graph above was (courtesy of Sparebank1  Markets) given my views on shale? I have been pretty consistent here that shale isn’t going to displace offshore, but it doesn’t need to in order to have a major impact on the economics offshore: It just has to take demand at the margin.

There are many graphs floating around like the one above. The Seadrill restructuring presentation contains this:

Seadrill offshore gap.png

Oceaneering had this graph recently:

Oceaneering Deepwater Demand.png

Ocean Rig has this one (while I agree with the headline the logic and data supporting this don’t make sense to me as the sanctioning replacement ratio has been historically over 100% for meaningful periods so a drawdown as firms pay down debt in a low price environment is logical):

Ocean Rig Industry Demand.png

You get the idea.

Schlumberger recently put the scale of shale production into perspective:

2017 Oil Supply

So to be clear: all tight oil had to do was add ~5% to the global supply and it has turned the entire offshore industry into a financial mess. Now it isn’t a strict causation, offshore has suffered a severe financial bubble based on oversupply as well as a demand crisis driven by the speed of change in the shale industry, but still it shows how finely balanced things were.

And indeed if you look at all the stories of hope and recovery that aim to recreate the world cast in a 2013 shadow they all profess unrealistically high utilisation and day rates at their core. The reason is obvious: the industry from 2007 was built on very high day rate levels and utilisation figues and any small change in those realities, given the very high fixed cost base, causes financial chaos.

A few percentage points in utilisation and day rates is all it takes to massively swing profitability in such a high fixed cost industry. Economic change happens at the margins.

Look at this chart from HugeStadSea which sums up the dominant thinking in the market (Q2 2017):

HSS Market Assumptions

Back to a cheeky 90% utilisation from 60%. Nice… what could go wrong?

Seadrill has the same:

Seadrill RP day rates

Everyone has the same story. But the problem is unless everyone is at very high utiilisation then day rates won’t pick up as the economic incentive for anyone with idle tonnage is to bid it cheap. Rowan in their latest results stated that they believed the market had to hit 85% utilisation before day rates improved.

So shale has an importance on the economics of offshore far beyond it’s output in the physical market displacing offshore oil as a source of supply. Shale only needs to reduce the utilisation of the offshore fleet by a few percentage points and that fundamentally changes the economics of rig and vessel companies. Seadrill, Solstad, Bibby, Technip DOF, in fact EVERYONE in the industry, is a completely different financial proposition at 51% utilisation compared to 91% with concomittant increases (or decreases) in day rates.

You also get an idea how large the investment in shale has been (Source: Schlumberger) since 2008:

Shale CapEx.png

25% investment since 2008 has gone into tight oil and it has seen productivity improvements like this (although the presentation highlights these rates are slowing):

Shale productivity.png

So I repeat again that that shale will not displace offshore as a source of supply. But it doesn’t need to in order to completely upset the economic structure of the offshore industry by lowering the amount of marginal demand generated where offshore service companies made profits above their fixed costs. By that I mean if your rig/vessel covered its costs and overheads on 85% utilisation and profits came after that (i.e. at 86% utilisation and above you started to be profitable), and the impact of tight oil is such that you only ever get to 85% for ever, then shale will have managed to removed excess profitability from the industry by ensuring a drop in demand at the margin. All shale needs to do is meaningfully alter the global fleet utilisation, and win a significant amount of E&P CapEx share, both goals shale has achieved, to have a massive impact on the offshore industry.

In economic terms this is what looks likely to happen:


The Demand (for offshore services) = the extra unit of revenue firms get for selling (Marginal Revenue) which matches the point where the extra costs of supply (Marginal Cost + Average Total Costs) balance. So yes, there will be more work, and assets may well be busier than they are now, but it could be just enough to keep everyone in the industry cash flow positive but making zero economic profit. I am not saying there won’t be accounting profits, that all firms will all be loss making, and all shares will go to zero, but I am saying firms will find it very hard to earn returns above their cost of capital.

The one prediction I will make is that any business model in this industry that just relies on an increase in day rates and utilisation is doomed unless it has a massive cash pile (because getting there is going to take a very long time) or you are buying assets at distress prices. But most of the distress investors have moved far too early and there is so much money floating around from these funds I think the distress funds are killing the price discovery mechanism in this market.

It is clear that the quantative deployment of capital in large E&P companies will have a significant portion focued on tight oil as well as offshore. A few percentage points, that could go either way in many companies, collectively have a huge impact on the global offshore fleet utilisation (and therefore dayrates) and that is the core impact shale has.

Structural and cyclical cost reduction and demand

A good article in the FT (behind the paywall sorry) but the core point is that the supply chain had better get used to a low cost procurement environment for a long time:

[C]uts have been made across the industry, pushing investment down to historic lows. The average number of new oil and gas developments given the go-ahead globally has fallen from 35 a year between 2010 and 2014 to just 12 since 2015, according to Patrick Pouyanné, Total chief executive. This number will have to increase, he said, if a supply crunch is to be avoided in the 2020s. He and other executives stress that reduced spending also reflects efficiency gains in the industry, allowing companies to do more for less…
Many of the savings stem from cuts forced on suppliers, such as rig operators, which were in no position to resist as business dried up after the oil price crash. But Bernard Looney, head of exploration and production for BP, insisted that two-thirds of reductions are structural, rather than cyclical, and would be sustainable. “It’s as much a story of how bad the past was as how good we have become,” he said. “We got the cost of Mad Dog 2 [a development in the Gulf of Mexico] down from $20bn to $8bn but frankly we should never have been at $20bn in the first place.”

The fact is for both rigs and vessels there is huge latent capacity and this will mean the supply chain is under pricing pressure for years. Offshore supply has structurally changed: it will become dominated by a few large players with massive fleets and low margins that mean scale is vital. Subsea contracting looks set to be dominated by a few large profitable contractors, in a flight to quality, while offshore support vessel owners who supply them will find it harder to make money due to long-lived over capacity. All this is a structural change in the industry and there is likely to be lower industry profitability regardless of how big a rebound is (when compared to 2010-2014).

When the number of projects starts to rebound, and it will take a long time to re-employ the engineering capacity required to do this, there will be a cyclical upswing as overall demand for these assets increases. But this is unlikely to see the entire industry benefit as a smaller number of companies at the contracting end of the market will still be able to use their market power to charter in excess capacity at a low marginal cost.

Whereas pretty much al business models used to work in offshore  that is patently not the case now.



“Short-cycle production” could be about to get an economic test…

The dots clearly show that oil prices and oil production are uncorrelated…

Caldara, Dario, Michele Cavallo, and Matteo Iacoviello

Board of Governers of the Federal Reserve System, 2016

The number of US oil rigs went down by 5 last week to 744 rigs, while the number of US gas rigs increased by 4 to 190 rigs. In terms of the large basins, the Permian rig count increased by 6 to 386 rigs, while both the Eagle Ford and Bakken rig counts declined by 3 each to 68 and 49 rigs respectively. 

Baker Hughes Rig Count, Sep 25, 2017


The multi-billion dollar question is: Can shale handle an increse in demand? Closely related: Is shale in a boom that is unsustainable and not generating sufficient cash to reward investors for the massive risk they have taken? Because if the latter is correct the former must be answered in the negative. The above quote is slightly mischevious and merely highlights economic research that supply factors have historically had a far bigger impact on the oil market than demand factors  (whether this is true going forward is not for today).

The NY Fed today reports that it is supply shortages now that are driving the price (and I have no idea about the construction of the model but the reduction in the residual leads me to believe it is broadly accurate), so this is a supply driven event not a demand driven event:

Oil Price Decomp 25 Sep 2017.png

If, as Spencer Dale argues (speech here), we are in the midst of a technical revolution then this is what we would expect. Hostoric levels of inventories should come down because supply is more flexible, these short-term kinks in demand caused by natural or geopolitical events should merely spur an increase in the rig count or a change in OPEC quotas. Other senior BP staff today were on message:

“Rebalancing is already on the way,” Janet Kong, Eastern Hemisphere Chief Executive Officer of integrated supply and trading at BP, said in an interview in Singapore. But OPEC needs “definitely to cut beyond the first quarter [2018]” to bring inventories down and back to historically normal levels, she said…

“If they extend the cuts, yes it’s possible” to achieve $60 a barrel next year, she said. “But it’s hard for me to see that prices will be sustainably higher,” she added.

Or is Permania simply the result of the Federal Reserve flooding the market with liquidity that is allowing an unsustainable production methodology to continue unabated storing up yet another boom and bust cycle? Bloomberg this week published this article on Permania, where the incipient signs of a bubble are showing in labour and infrastructure shortages and the outrageous cost overruns:

Experienced workers are harder and harder to find, and training newbies adds to expenses. The quality of work can suffer, too, erasing efficiency gains. Pruett said Elevation Resources recently had a fracking job that was supposed to take seven days but lasted nine because unschooled roughnecks caused some equipment malfunctions.

By this point, “we’ve given up all of our profit margin,” he said, referring to the industry. “We’re over-capitalized, we’re over-drilling and, if prices don’t rise, we might be facing a double dip in drilling.”

If I was being cynical about offshore production I would note that he was two days over with a rig crew while in the same calender week Seadrill and Oceanrig had collectively disposed of billions of investment capital and will still have the inventory for years. This guy is literally two days out of forecast and he is worried about being over-capitalized (and also that wiped his profit margin? Hardly redolent of a boom?) Offshore drilling companies are like 10 years and 100 rigs out of kilter… Anyway moving swiftly on…

Bloomberg also published this opinion on Anadarko noting:

Late on Wednesday, Anadarko Petroleum Corp., which closed at $44.81 a share, announced plans to buy back up to $2.5 billion of its stock; which is interesting, because almost exactly a year ago, it sold about $2 billion of new stock — at $54.50 apiece.

(That’s pretty clever, they sold stock at $54.5 and are buying it back at $44.8, like Glencore never buy off these people when they are selling, at heart they are traders. More importantly most research suggest companies nearly always overpay when buying stock back so if the oil price keeps creeping up they are going to look very smart indeed.)

But the real point of the story is that capital is slowing up to the E&P sector, well equity anyway no mention of high-yield:

Equity US E&P Sep 2017

Meaning that maybe people are getting sick of being promised “jam tomorrow”. However I can’t help contrasting this with productivity data, Rystad on Friday produced this:

Rystad Shale Improvement Sep 17

So despite the anecdotal evidence on cost increases in the first Bloomberg article the productivity trend is all one way.  And the stats seem clear that a large part of deepwater is at a structural cost disadvantage to shale:

ANZ cost structure 2017

Frac sand used to be c.50% of the consummables of shale, but surprise:

Average sand volumes for each foot of a well drilled fell slightly last quarter for the first time in a year, said exploration and production consultancy Rystad Energy. Volumes are expected to drop a further 2.5 percent per foot in the current quarter over last, Rystad forecast…

Companies including Unimin Corp, U.S. Silica Holdings Inc (SLCA.N), and Hi Crush Partners LP (HCLP.N) are spending hundreds of millions of dollars on new mines to address an expected increase in demand.

On Thursday, supplier Smart Sand SND.O reported it shipped less frack sand in the second quarter than it did in the first. Rival Fairmount Santrol Holdings Inc (FMSA.N) forecast flat to slightly higher volumes this quarter over last.

In the last six weeks, shares of U.S. Silica and Hi Crush are both off about 30 percent. Smart Sand is off about 43 percent since June 30…

Some shale producers add chemical diverters, compounds that spread the slurry evenly in a well, and can reduce the amount of sand required. Anadarko Petroleum Corp (APC.N) and Continental Resources Inc (CLR.N) are reducing the distance between fractures to boost oil production. The tighter spacing allows them to extract more crude with less sand.

Technological innovation and scale: Less sand used and increased investment going on that will reduce the unit costs of sand for E&P producers. This is the sort of production that brought you the Model T in the first place and the American economy excels at. Bet against if you want: just remember the widowmaker trade.

Shale is a mass production technique: eventually it will push the cost of production down as it refines the processes associated with it. To be competitive offshore must emulate these constantly increasing cost efficiencies. I have said before that shale won’t be the death of offshore but it will make a new offshore: a bifurcation between more efficient fields, low lift costs, and economies of scale in production that make the “one-off” nature of the infratsructure cost efficient, and smaller, short-cycle E&P of shale (and some onshore conventional).

Offshore is going to be here for a long time, it is simply too important in volume terms not to be. But what a price increase is not going to see is a vast increase in the sanctioning of new offshore projects in the short-term. These will be gradual and provide a strong base of supply, as there longer investment cycle represents, while kinks in short-term demand will be pushed towards short cycle production. Backlog, or lack thereof, remains the single biggest threat to all offshore contractors.

Or this thesis is wrong and I, and to be fair people far cleverer (and more credible) than me, are spectacularly wrong, and a new boom for offshore awaits in the not too distant future…

The narrative in capital allocation moves to shale…

I use the term narrative to mean a simple story or easily expressed explanation of events that many people want to bring up in conversation or on news or social media because it can be used to stimulate the concerns or emotions of others, and/or because it appears to advance self-interest. To be stimulating, it usually has some human interest either direct or implied. As I (and many others) use the term, a narrative is a gem for conversation, and may take the form of an extraordinary or heroic tale or even a joke. It is not generally a researched story, and may have glaring holes, as in “urban legends.” The form of the narrative varies through time and across tellings, but maintains a core contagious element, in the forms that are successful in spreading. Why an element is contagious, when it may even “go viral,” may be hard to understand, unless we reflect carefully on the reason people like to spread the narrative. Mutations in narratives spring up randomly, just as in organisms in evolutionary biology, and when they are contagious, the mutated narratives generate seemingly unpredictable changes in the economy.

Shiller, 2017

News that BP had started production at Quad 204 (Schiehallion) led curmudgeonly FT columnist Lombard to note  yesterday:

If anything, then, Monday’s news is more of a last hurrah for BP in the North Sea, and for the UK Continental Shelf more broadly. With the strongest capital flows — and investor buzz — focused on unconventional US resources, traditional offshore oil can seem as fashionable as a set of free “crystal” tumblers from a 1970s petrol station. With a big shield logo.

I have mentioned here before that behavioural finance is starting to examine the narrative in economics (see initial quote), and at the moment this is the narrative in London and other capital markets. This ties in nicely with an excellent piece from Rystad earlier in the week looking at the future of the North Sea and the Gulf of Mexico (I recommend reading the whole thing). For service companies Rystad notes:

After such a deep cut in this market it will take some time before the industry experiences a full recovery. Even with oil prices of $90/bbl to $100/bbl for the next decade, the market will not be back to 2014 levels before 2024.

The link for me is that offshore is going to bifurcate into huge developments (Quad 204, Mariner, Bressay, Mad Dog 2) and “the rest”. The rest are unfortunately going to be much smaller in number and less frequent. Rystad specifically mentions the lack of tie-back and tie-in projects in these regions. These projects are the investments that really compete with shale: 8-12 000 bpd that were ignored by larger E&P companies. The larger developments with high flow rates, and multi-decade economic plans, are vital for security of volume and a core underpinning of E&P profitability, and they are very economic, playing to super-major strengths of vast capital requirements combined with astounding engineering capability; but smaller developments in the USD 50-200m range are at a real risk of grinding to a slow halt for all except the companies currently committed to this space.

The North Sea, and to a lesser extent GoM, always had a significant number of smaller players (think Ithaca Energy (recently sold to Dalek) or Enquest), that raised (relatively) small sums of money and then sought to regenerate an exisiting area or develop smaller finds. Access to financing for that market simply doesn’t exist at the moment on anything like the scale it did before. Those Finance Directors who used to traipse around fund managers in London, Vancouver, New York etc with a deck of slides explaining their proposed developments are simply not getting a hearing. Not only that the tried and tested business model of developing a few fields and selling out with a takeover premium when they had built sufficient scale isn’t credible any more as potential acquirers focus on more on tight oil. Now those fund managers are meeting with guys who have a deck of slides that start with a shale rig, emphasise the relatively low upfront capital (as opposed to the higher OpEx) and their ability to rein in variable costs should price declines occur. The meme in financial markets now is all about shale, and rightly or wrongly, influential columns such as the one above help set this “dominant logic”.

Inside the big E&P companies managers, who are cognizent of the fact they must deal with analysts in the financial community and the investor base who follow the same narrative, are adapting and spending more time to examining potential shale investments. Offshore is getting less airtime. When was the last time you hard someone say “all the easy oil is gone” – which was taken as fact only 5 years ago. From this myriad of individual meetings and actions the macro picture of slowing capital flows into offshore and increased investment in shale is being driven, and it will be very hard to reverse without some exogenous event.

As behavioural economics teaches us humans are “boundedly rational” not the perfectly rational homo economicus so beloved of the efficient markets crowd. What this means is that potential investors can only process so much information, if you combine this with the fact that institutional investors “herd” (i.e. invest where their competitors do), you can see the current investment vogue is short cycle shale which makes even getting funding hard even for compelling offshore investments. Those who have heard the word “Permania” used to describe the boom in Permian basin will relate to this quote from the IMF on investment herding:

[p]rocyclicality in asset allocation can make swings in financial asset value and economic activity more intense. From an individual investor’s point of view, procyclical behavior can be rational, especially if short-term constraints become binding or if the investor can exit earlier than others. However, the collective actions of many investors may lead to increased volatility of asset prices and instability of the financial system..

Eventually the shale mania will wain as people overpay for land and productivity improvements slow. The problem for offshore is the amount of OpEx people will have to burn to get to this point and the consistently increasing productivity of shale.

Big players in the North Sea region like Apache, Taqa, and Sinopec will conitnue to develop offshore fields but they are not doing as many projects. The threshold rate for investment will be higher, because experience has taught us that you can get 5 years of low oil prices and many of these projects only have economic lives of 5-10 years (risk models are great at solving previous issues). These companies have less access to capital markets than their shale competitors because the high-yield desk has the same meme as the equity investors, higher equity costs and more risk averse bank funding raise project return requirements even more. Even state -backed companies like Taqa must vie for funding internally. Outside of the North Sea and GoM these developments are likely to remain dominated by National Oil Companies who may not rank projects on a strictly economic basis but will take the expected spot price of oil into account in their investment decisions. But as Rystad makes clear the North Sea and GoM volume increases will all be driven by a smaller number of larger projects.

This affects contractors differently. As Rystad notes EPIC work will decline proportionately less than other work.  For DSVs and ROV operators and vessel owners) this is grim . Until construction work, that uses far more DSV and ROV days than maintenance work, improves the supply side of the industry will take the adjustments both in day rates and utilisation levels. The supply chain is going to change into a few large integrated contractors in these regions with a vast choice of assets to service their needs and they are likely to reduce their comitted charter tonnage . These large contractors will make an economic return but part of it will be done by ensuring the smaller companies in the supply chain make only enough economic profit to survive and the equity value (if any) in these companies and assets looks set to be depressed for an extended period. Consolidation on a scale only dreamed of at the moment amongst vessel owners looks certain.

Demand will not return for smaller projects until the market price for oil stabilises at a substantially higher price than now, and does so for long-enough to give potential funders confidence that the upturn isn’t temporary. The uplift will likely be less severe because shale has introduced a “kink” in the supply curve. Projects take time to pass through engineering, funding etc before meaningful offshore work occurs. This is a long-term issue: Demand may have stabilised at current levels but recovery for the supply chain that is based on the realistic prospect of higher days rates and utillisation looks some way off.  For an asset base built to supply a 2013/14 demand curve the outcome looks uncomfortably obvious.