Group think and conventional wisdom…

“It will be convenient to have a name for the ideas which are esteemed at any time for their acceptability, and it should be a term that emphasizes this predictability. I shall refer to these ideas henceforth as the conventional wisdom.”

J.K. Galbraith, The Affluent Society


“All that we imagine to be factual is already theory: what “we know” of our surroundings is our interpretation of them”

Friedrich Hayek


We find broad- based and significant evidence for the anchoring hypothesis; consensus forecasts are biased towards the values of previous months’ data releases, which in some cases results in sizable predictable forecast errors.

Sean D. Campbell and Steven A. Sharpe, Anchoring Bias in Consensus Forecasts and its Effect on Market Prices

Great quote in the $FT yesterday that reveals how hard it has been in the oil and gas industry for professional analysts to read the single biggest influencing factor that is reshaping the supply chain: rising CapEx productivity and its ongoing continued pressure. Money quote:

Mr Malek said that with the notable exception of ExxonMobil, most energy majors had shown they were capable of growing output quickly even when investing less than it used to.

“We all thought production was going to fall off a cliff from Big Oil when they started slashing spending in 2014,” said Mr Malek. “But it hasn’t. The majority of them are coming out on the front foot in terms of production.” [Emphasis added].


An outlook where E&P companies can substantially reduce CapEx and maintain output is not one in a lot of forecast models. Forecasts are rooted in a liner input/out paradigm that leads to a new peak oil doomsday scenario. But the data is coming in: E&P companies are serious about reducing CapEx long term and especially relative to output, and collectively the analyst community didn’t realise it. The meme was all “when the rebound comes…” as night follows day…

The BP example I showed was not an aberration. For a whole host of practical and institutional reasons it is hard to model something like 40% increase in productivity in capital expenditure. But the productivity of E&P CapEx, along with the marginal investment dollar spend,  has enormous explanatory power and implications for the offshore and onshore supply chain.

Aside from behavioural constraints (partly an availability heuristc and partly an anchoring bias) the core reason analysts are out though is because their models are grounded in history. Analysts have used either a basic regression model, which over time would have shown a very high correlation between Capex and Output Production, or they simply divided production output by CapEx spend historically and rolled it forward. When they built a financial model they assumed these historic relationships, strong up until 2014, worked in the future… But these are linear models: y if the world hasn’t changed. The problem is when x doesn’t = anymore and really we have a multivariate world and that becomes a very different modelling proposition (both because the world has changed and a more challenging modelling assignment). We are in a period of a  structural break with previous eras in offshore oil and gas.

These regressions don’t explain the future so cannot be used for forecasting. No matter how many times you cut it and reshape the data the historical relationship won’t produce a relationship that validly predicts the future. At a operational level at E&P companies this is easier to see: e.g. aggressive tendering, projects bid but not taken forward if they haven’t reached a threshold, the procurement guys wants another 10k a day off the rig. There is a lag delay before it shows up in the models or is accepted as the conventional wisdom.

SLB Forecast.png

Source: Schlumberger

Over the last 10 years, but with an acceleration in the last five, an industrial and energy revolution (and I do not use the term lightly) has taken place in America. To model it would actually be an exponential equation (a really complicated one at that), and even then subject to such output errors that wouldn’t achieve what (most) analysts needed in terms of useful ranges and outputs. But the errors, in statitics the epsilon, is actually where all the good information, the guide to the future, is buried.

But when the past isn’t a good guide to the future, as is clearly the case in the oil and gas market at the moment, understanding what drives forecasts and what they are set up to achieve is ever more important. How predictive are the models really?

A lot of investment has gone into offshore as the market has declined. A lot of it not because people really believe in the industry but because they believe they will make money when the industry reverts to previous price and utilisation levels, a mean reversion investment thesis often driven on the production rationale cited in the quote. Investors such as these have really being buying a derivative to expose themselves, often in a very leveraged way, to a rising oil price, assuming or hoping, frankly at times in the face of overhwelming contrary evidence, that the historic relationship between the oil price and these assets would return.

These investors are exposed to basis risk: when the underlying on which the derivative is based changes its relationship in its interaction with the derivative. These investors thought they were buying assets exposed in a linear fashion to a rising oil price, but actually the structure of the industry has changed and now they just own exposure to an underutilised asset that is imperfectly hedged (and often with a very high cost of carry). Shale has changed the marginal supply curve of the oil industry and the demand curves for oil field services fundamentally. Models utilising prior relationships simply cannot conceptually or logically explain this and certainly offer zero predictive power.

The future I would argue is about the narrative. Linking what people say and actions taken and mapping out how this might affect the future. To create the future and be a part of it you cannot rely on past hisotrical drivers you need to understand the forces driving it. Less certain statistically but paradoxically more likely to be right.

Oil prices, technology, volatility, and productivity…

Oil prices are unusually prone to volatility because both supply and demand are insensitive or “sticky” in responding to price changes in the short term, while storage is limited and costly.

Robert McNally, Rapidan Energy Group


Last week Citi’s lead oil analyst came out and said he thought oil prices might dip to $45 per barrel in 2019 and be in the $45-65 per barrel range by the end of 2019. This contrasts with Goldman Sachs ($70-80), Morgan Stanley ($85), and Bernstein ($100). I don’t have a view on the oil price, all this shows you is that intelligent, well-informed analysts, with almost endless resources, can vary in their forecasts by around ~50-100%. Read the whole story to understand how looking at exactly the same data set as all the other equally capable analysts Citi’s analyst reaches such a different conclusion.

What this really shows is model risk: a few percentage points difference in key input variables, even over a short space of time, can have a huge influence over the outcomes. And actually, there are in reality too many influences to model them all accurately: Will there be a supply outage in Libya? What will happen with Iranian oil? What will happen in Venezuela? And these are just a few of the big geopolitical questions alone. You need a forecast for many planning assumptions but in the short-run the oil price is a random walk.

A good example is this graph from the EIA showing the difference between their February prediction of US oil prediction and the current one:


If you are wondering why your jack-up, rig, or vessel isn’t quite getting the utilisation or day rate you were looking for in that graph may lie the answer? It’s a bold Board that sanctions too many projects in this environment, and in fact the one that is, Exxon Mobil with the huge Guyana finds, is getting slammed by the stock market. Barclays, summing up the “market view” saying:


Shale isn’t a swing producer as McNally makes clear, but it does have a much shorter-term impact on the market in way that nothing did prior to 2013. But it also isn’t a given that offshore will have a cost or volume advantage over offshore in 10 years time: companies need to hedge their bets if they are large portfolio corporations. McNally has published ‘Crude Volatility‘ which may make  my summer reading list.

The big area where I agree with Citi/Morse is on technology and productivity.  Morse obviously believes, as I do, that a few percentage points of recovery and technological improvement over the well lifecycle has the potential to radically alter physical oil output assumptions over the long-run. And that is before you get into the wonkish areas such as on what base you forecast the decline volume on.

Against this backdrop is a new wine in the old bottle of peak oil demand: lack of investment and the coming supply shortage. A whole host of energy consulting firms say underinvestment may cause a supply driven price rise: Rystad and Energy Aspects in this WSJ article:


This despite the fact that gross investment doesn’t reflect the increased volume of supply gained from each incremental dollar at the moment (a point Morse makes), or the fact that oil companies don’t need the same level of reserves now (and investors don’t want them to pay for them).  Woodmac, who in the latest “gotcha” on why shale won’t work (sic), has now discovered shale well rates decline faster than thought… I’ll bet by 2040 the 800k a day production cited in the article is made irrelevant by productivity improvements in extraction and production techniques. But I guess again it shows how senstive large data models are to small input changes (and how desperate research firms are to have some uncertainty and upside to discuss with certain corporate clients where an element of group think appears to be pervading Board thinking).

“Preparing for the Recovery”

Preparing for the future.png Rystad also run’s strategy days for Maersk Supply and numerous other subsea and offshore companies…. “Hang in there guys the recovery is just around the corner when the supply crunch happens…”… (however remember The Dominant Logic is dangerous?)….

Meanwhile the capital deepening in the US shale industry continues apace. Have a look at the new pipelines going in:


Once these are built the price discount will disappear, further raising E&P company profitability and some railway carriages and trucks they displace will still exist (‘unit trains’ with 100+ carriages carry >66 000 barrels). Some will be scrapped but the railway carriages are like offshore vessels: high fixed costs and commitments and low marginal costs. That is a short way of saying they will reduce their costs to compete… and the virtuous cycle will continue with the capital base even deeper.

What really matters for offshore at the moment is the competition for marginal investment dollars. Does an E&P company choose to invest onshore or offshore? The big advantages of shale are potential productivity increases and lower upfront cash costs despite a lower margin (i.e. low CapEx high OpEx), this flexibility has a number of distinct advantages in  an era when forecasts are so divergent. It is worth noting that Shell, Exxon Mobile and Chevron all underperformed the stock market last week despite oil prices having risen signficantly over the last year. Shareholders want their money back in an era of uncertainty, not mega-projects that offer future pay-offs.

In an era when the volatility of oil prices is clearly increasing you can be sure that tight oil will be favoured over long cycle production at the margin. The ability to take margin risk over commitment risk is a key part of the investment making decision process.  The graph above shows how volatile oil prices has been, in particular since 2003. It is irrational to go long on fixed commitments in a age of increasing volatility: just as it is illogical to take on a massive mortgage on a rig or vessel in the current market it is illogical to go long on too many 20 year deepwater developments, and the two symptons are obviously related to the same cause. For a baseload of demand that is logical, but that only works for the larger players with significant market share, at the margin assets and projects become harder to finance.

The other issue driving investment towards shale, in a time of capital discipline, is path dependence. Path dependence is a process where each step forward can only be achieved with the prior steps preceeding it. Deepwater followed shallow water as an extension of the skills developed there.

The productivity benefits of shale are such that larger E&P companies must fear if they miss this technology cycle catching up on the “path” may be too hard or expensive given the dependent steps they will have to get there. History matters.

Offshore will remain an important part of the energy mix. But the price rise of the past 12 months has led to only marginal increases in work and a firm commitment from E&P companies to control CapEx in a manner that breaks with the past. Price rises not increases in long term production projects are the short term adjustment mechanism at the moment. In a era of price volatility and extraordinary technical change the future could look a lot like the present.

“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.

For the tier 2 contractors summer isn’t coming… a long hard grind beckons…

Back in the dark ages of November 2016 a consensus was forming amongst the more optimistic of the subsea and investment community: things had got so bad there must be an upturn in 2017? M2 raised money from Alchemy, the Nor DSV bondholders did a liquidity issue, SolstadFarstad started their merger discussions, York began acquiring a position  in the Bibby bonds, Standard Drilling went back to the market to buy more PSVs (could they be worth less?), and early in 2017 on the same wave Reach also raised money… what could possibly go wrong? A quick rise in the price of oil and the purchase orders would flow robustly again… risk capital would have covered essentially a short-term timing issue and as the summer of 2017 came things would revert, if not back to 2014, at least some degree of normalcy and cash profitability. Everyone would be positioned for the next big upturn… This wasn’t a solvency issue for the companies involved figured the investors, this was merely a liquidity issue that they could profit from by supplying the needed funds…

Things haven’t quite worked out the way they planned. Summer, in terms of high day rates and utilisation didn’t come last year, and it hasn’t come this year with sufficient force to change much this year, but next year the true believers tell you it will be massive. Bigger than ever. You just need enough money to cover another loss-making winter to get there…

No one can know the future, although I think many of the signs were there, and a lack of any due diligence was a common theme of many of the above transactions; but the real question now is when the industry accepts the scale of the change required and the necessary exit of some capital to reflect new demand levels? Or not maybe? There is so much excess liquidity (that’s the technical term for dumb money) floating around, and the capital value of the assets in  subsea is perceived as so high, maybe another cycle of working capital to burn beckons… but certainly not for everyone. And there will be some mean reversion here but it is looking on the downside not the up.

Alchemy Partners appear to have realised this and seem committed to a quick exit from M2, the sale process appears to be highly geared to an asset only deal. Such a transaction would save them from the timing and cost of issuing a full IM, due diligence, and the time spent negotiating an SPA for a loss-making business that a self professed special situations investor cannot bring itself to commit more to. The first question anyone would ask them would be “why is one of the once great names in UK retsructuring unable to make this work?”.  Reputational risk alone for them argues for a quick process here… With XLXs going for $1.5m used Alchemy may feel they get just as much from a clean asset sale as from any possible going concern basis, when matched with the profits made from being in the Volstad Topaz bond they may not come out too badly here.

Reach Subsea have decided the numbers are so bad that their Q1 2018 results won’t appear on the website. (Reach aren’t the only people playing this strategy; for all their entrenched bureaucracy Maersk Supply can’t seem to find their numbers to put up after Q3 last year either). As a general rule in this market if you aren’t putting up numbers it’s because they are even worse than people feared.

For Reach Subsea one is treated to  the newshub with a few bullet points of “financial highlights”. It is hard to comment without seeing the full financial statements but Subsea World News appear to have seen the full numbers and say that turnover was NOK 114m and operating costs were NOK 101m ROV days sold were up 89% and EBITDA was up to NOK 13.2m. However, losses before tax were up 50% on the same period last year. This could just be an accounting convention as part of the change to a new accounting standard for leases, but with M2 unprofitable, along with a host of other ROV companies, the chances of Reach making money with exactly the same business model and service offering have to be regarded as remote.

The spot market nature of the Reach business is highlighted by the fact that their order book is at NOK 147m (mostly for 2018) which is 10%< of the amount of work they are bidding for in the pipeline. Everyone goes on about tendering but it’s a real cash cost and if you aren’t winning 30% of the work you are tendering for then you are tendering too much and just wasting time and resources. Tendering NOK 1.7bn in work implies Reach Subsea should turnover about NOK 600m this year, with their firm pipeline at NOK 147m in Q1 that has seem a long way off.

All these companies are doing is providing capacity at below economic rates of return and burning OpEx in a way thay ensures the industry as a whole cannot make a profit. Eventually investors, not usually management because these are lifestyle businesses, tire of this. ROV rates are such at the moment that even though most are purchased with only a 20% deposit operators are not making enough to cover the deposit on a new one when they wear out. Eventually the small players get ground out because even if they can survive in operational terms hopes of replacing equipment becomes a fantasy. This is how the industry appears to be reducing capital intensity.

I have expressed my scepticism consistently on the ROV industry on many occassions based on one simply premise: Oceaneering. Oceaneering is the market leader, widely regarded as a well run company and has signficant economies of scale and scope, and even they can’t make money off ROVs. Neither could Subsea 7 in  the i-Tech division… so how on earth are all these small companies going to make money? All they can sell on is price, and there is sufficient overcapacity to ensure the E&P companies play all the tier 2 contractors off against each other. To my mind this is one of the drivers of increased tendering that all the tier 2 contractors claim while their numbers become even worse.

Oceaneering is by an order of magnitude the largest ROV company in the world:

Oceaneering market position.png

And yet with all that scale cash flow is getting worse:

Oceaneering FCF.png

That’s not a reflection of Oceaneering management that is a reflection of market conditions. And if the largest company in the industry can’t get any uplift then the small companies, with no pricing power, are also operating at a significant loss without the resources of the larger companies. Talk of other companies doing a buy-and-build strategy in the ROV market is just laughable given the sheer scale of the top 5 companies controlling more than 50% of the market. Someone got there first 10 years ago, and executed well, this isn’t the market for an imitator it is  the market for large industrial players to grind out market share.

What is happening, and will continue to happen, is that those companies with scale and resources will continue to grind out market share and volume by pricing at whatever they can get (in economics terms below marginal cost) and they can keep this game up longer as they have more resources. It is just that simple.

DOF Subsea, DeepOcean, and Reach Subsea, have within days of each other announced they have framework commitments from Equinor. Such “contracts” (in the loosest sense of the word only) guarantee no work just a pricing and standards level from the contractors. The only obvious economic implication from this contracting method is that Equinor believes it doesn’t need to cap it’s costs going forward as overcapacity will keep rates down. Equinor is keeping it’s options open and help keep some small Norwegian contractors alive to prevent SS7 from Technip from strangling them, but it’s generosity appears limited. (It should also be noted Saipem/Aker appear to be making real moves now to bid the Constellation and Maximus in Norway so even tier 1 rates there look set to suffer.)

DeepOcean is the one company that appears to really be on the point of being regarded as a tier 1 contractor in terms of IRM and renewables scale. Acquisitions at the bottom of the market in Africa and the US, a smart charter of the Rieber vessel, and a large European business with a strong renewables business have probably given it enough scale to be regarded as in a different league now from the smaller companies. But it shows the size of commitment a buy-and-build strategy would require and the industry simply doesn’t have enough inherent profitability to make it worthwhile. A point Alchemy have now implicitly acknowledged and their commitment to the socialist idealogy of helping E&P companies lower maintenance costs by supporting them with investors funds seems to have ended. DeepOcean should probably be regarded as the minimum efficient scale a company in this market needs to be to survive, a vast mountain to climb for any investor coming in this late no matter how cheaply they buy some kit.

For all the tier 2 contractors there is no respite. Pricing pressure will remain extreme, they have identical business models and assets, there is no scope for differentiation, and capacity far outstrips any reasonable expectations of demand inceases. Make no mistake Alchemy won’t be the first to throw in the towel and other investors need to think what they know that Alchemy Partners doesn’t? For as long as the industry can find investors willing to believe the downturn is a normal cyclical part of the oil industry, rather than a secular change where the relationship between the oil price and offshore expenditure has fundamentally changed (a regime shift in econometrics) then this seems to be the only likely outcome.

Overdiscounting… the future of offshore…

The qualities most useful to ourselves are, first of all, superior reasons and understanding, by which we are capable of discerning the remote consequences of all our actions; and, secondly, self-command, by which we are enabled to abstain from present pleasure or to endure present pain in order to obtain a greater pleasure in some future time.

Adam Smith, 1759


For most of these persons are, in fact, largely concerned, not with making superior long-term forecasts of the probable yield of an investment over its whole life, but with foreseeing changes in the conventional basis of valuation a short time ahead of the general public. They are concerned, not with what an investment is really worth to a man who buys it ‘for keeps’, but with what the market will value it at, under the influence of mass psychology, three months or a year hence.

John Maynard Keynes, 1936


The slide above taken from Transocean highlights how competitve offshore has become on a per barrel recovered basis. I’ll ignore the fact that the cost estimates for shale appear high because it isn’t my point: the real point is that to compete in the modern environment offshore oil production will have to be significantly more profitable on a per barrel recoverable basis because there is significant evidence managers underestimate (“overdiscount“) future financial returns the further away they are. Shale returns, while lower, are produced in a much shorter time period than offshore and behavioral finance shows strong evidence that managers prefer these sorts of returns at lower levels when compared to higher returns further away.

In  2011 Andrew Haldane, Executive Director, Financial Stability at the Bank of England, and Richard Davis, and Economist at the Bank of England spoke at a Bank for International Settlements conference and noted:

[r]ecently, in 2011 PriceWaterhouseCoopers conducted a survey of FTSE-100 and 250 executives, the majority of which chose a low return option sooner (£250,000 tomorrow) rather than a high return later (£450,000 in 3 years). This suggested annual discount rates of over 20%. Recently, Matthew Rose, CEO of Burlington Northern Santa Fe (America’s second biggest rail company), expressed frustration at the focus on quarterly earnings when locomotives lasted for 20 years and tracks for 30 to 40 years. Echoes, here, of “quarterly capitalism”.

In 2013 McKinsey & Co and CPPIB surveyed 1000 Board members and found:

  • 63% of respondents said the pressure to generate strong short-term results had increased over the previous five years.
  • 79% felt especially pressured to demonstrate strong financial performance over a period of just two years or less.
  • 44% said they use a time horizon of less than three years in setting strategy.
  • 73% said they should use a time horizon of more than three years.
  • 86% declared that using a longer time horizon to make business decisions would positively affect corporate performance in a number of ways, including strengthening financial returns and increasing innovation.
  • 46% of respondents said that the pressure to deliver strong short-term financial performance stemmed from their boards—they expected their companies to generate greater earnings in the near term.

The implications for offshore investment (decision tree here) versus the certainty of a short payoff from shale investment are obvious. It has been well known in economics for years that managers overdiscount future returns: in behavioural economics it falls under time preference problems. Humans are neurologically wired with a preference for immediacy that affects economic behaviour. As Haldane and Davis make clear:

This evidence – anecdotal, survey, quantitative – is broadly consistent with popular perceptions. Capital market myopia is real.

As early as 1972 Mervyn King, who would later become Governor of the Bank of England, noted that managers in the UK overdiscounted returns from long term investments. This stream of literature dried up as the Efficient Market Hypothesis took over as the vogue theory but it doesn’t change an actual reality.

The fact is that in competition for marginal oil investment dollars there are institutional and behavioural factors pushing for short-term solutions. This article in the Financial Times notes that Shell is under pressure as the CFO hasn’t outlined when the promised $25bn share buyback will start. Do you think the CFO at Shell is pushing for a new Appomattox because it has lower economic costs (but high CapEx) or will she simply seek to favour short pay-off, lower margin, projects?

Managers pushing offshore projects in E&P companies are running into senior managers who represent exactly those type of Board members surveyed by McKinsey and CPPIB. These managers aren’t wilfully myopic, the shareholders are pushing them to be, but they are more focused on immediate payoffs and overdiscounting the costs of the offshore projects. Again this quote from Haldane and Davis seems apposite:

Graham, Harvey and Rajgopal (2005) surveyed 401 executives. They found three striking results. First, managers would reject a positive-NPV project if that lowered earnings below quarterly consensus expectations. Second, over 75% of the sample would give up economic value in order to smooth earnings. Third, managers said that this was driven by the desire to satisfy investors.

When there was no shale this wasn’t an option as the question was “Do you want oil or not?”. The question is a whole lot more complex now and involves and assessment of certainty, risk, payoff potential and timing, and the pricing uncertainty of a volatile commodity over the long run. All this points to the fact the the financial and institutional barriers to new offshore projects are much higher than simple “rational” expectation models of future payoffs would suggest.


The trade-off between shale and offshore investment and the effects on marginal demand…

The rising oil price is about to test one of the major tenets of this blog: namely that there has been a structural change in how oil is produced and that a sharp comeback in offshore demand, as has been seen in previous cycles, is extremely unlikely. At the moment all the data appears to be pointing to the ever increasing importance of shale over offshore for marginal investment dollars, and in fact the higher price may be encouraging shale investment over offshore as smaller E&P companies can meet volume increases through cash generated and open capital markets and larger E&P companies take a margin hit but keep CapEx commitments steady and not expanding offshore much beyond long signalled commitments.

It is also worth noting that this recent price rise does not seem related to demand factors:

physical markets for oil shipments tell a different story. Spot crude prices are at their steepest discounts to futures prices in years due to weak demand from refiners in China and a backlog of cargoes in Europe. Sellers are struggling to find buyers for West African, Russian and Kazakh cargoes, while pipeline bottlenecks trap supply in west Texas and Canada.

At the moment Permain is trading on a discount to WTI of between $7-12 per barrel given transportation constraints via pipeline out of the region. Something like 1.5m barrels per day opens up by March next year though so this is a temporary problem. The process of capital deepening for shale is also occuring as refineries in the region change their intake capacity for the ‘light sweet’ crude that currently needs to be mixed with heavier Brent. This will take time, and cost billions, but every year this capacity slowly increases with each maintenance cycle at the large refineries, incentivised by the large discount to Brent.

PVM has reported that as the oil price has rised Texas’s energy regulator issues 1,221 drilling permits in April, up around 34% from a year ago. The BH rig count added another 10 rigs to the US oil fleet last week but also another 2 offshore rigs, but that only brought the offshore count back to a year ago, the same for the Gulf of Mexico (+1); whereas the land rig count is up ~19% from a year ago.

BH rig count 11 May 2018.png

Again this leads directly to higher production. In June alone US shale production will add the rough equivalent of a Clair Ridge to their output levels:


The US shale industry is the single biggest transformation to the oil and gas industry since the pre-salt fields were discovered and developed in Brazil. Those developments led to an extraordinary rise in the price of tonnage and changed the entire offshore supply chain. It is simply not logical to accept that a change as big as this in volume terms is occurring in the US and that it will not have similarly profound impact on the offshore industry.

The correlation between the oil price and the US rig count and the oil price and US production levels has an r-squared of ~.6 according to IHS Markit (data below) if anyone is interested. That means each $1 increase in the price of oil leads to a .6 increase in the rig and production volumes.


Whereas for offshore a strong increase in the price of oil over the last twelve months has seen this happen to the jack-up and floater count:

Jackup and rigs 11 May 18.png

Source: Pareto Securities.

Jack ups and Floaters demand has been effectively static over the past year. The workhorses of future offshore production increases and demand simply haven’t moved in a relative sense. The cynic would argue their correlation to the oil price has been reduced to zero (which clearly isn’t true), but it shows how time delayed this recovery cycle is for the front end of offshore. But the flat demand for jackups and floaters is exactly what most subsea vessel and supply companies are saying: demand has bottomed out but over supply and a lack of pricing power persists. The good explanation of why so many OSV and subsea companies claim to be doing record tendering and their  continued poor financial performance lies in the data above.

What I call (sic) “The Iron Law of Mean Reversion”, which seems to substitute for thoughtful analysis, can be seen in this slide:

Transocean Iron Law.png

The heading is simply a logical fallacy. There is a load of evidence to say shareholders are more comfortable with lower reserves now and less offshore production is being sanctioned because the money is being spent on shale.

At some point the disconnect between companies like Standard Drilling, buying PSVs at pennies in the dollar and keeping them in the active fleet, and the general oversupply will be realised. In the CSV/ Subsea fleet things are no different: Bourbon, Maersk, and other vessel owners state they are building up contracting arms, yet again all they do in total is keep supply high for a relatively undifferentiated service and erode each others margins (and spend a lot on tendering). The service they operate has no real differences to the ROV companies like Reach, M2, ROVOP, IKM ad infinitum and other traditonal vessel contractors like DOF Subsea. Sometimes they have a good run of projects… and other times…

Bourbon Q1 2018 Susbea.png

Project work is lumpy but Bourbon stated that the project market was especially poor versus suppy. In the old days boats were scarce and enginneering had a relatively small mark-up which the mark-up on the vessel accentuated and flattered. But getting a CSV with a large deck and crane now is so average it is no wonder everyone claims to be tendering: E&P companies are clearly getting them all to bid to reduce project costs. There is clearly more work being done on vessels at the moment, but there is a limit as shown above, and no project delivery companies have any pricing power.

The larger contractors appear to be winning a greater porportionate share of work at ever lower margins as TechnipFMC recently showed:

Technip Q1 2018.png

Given Technip is now winning as much work as it burns through demand has clearly hit the bottom. But even it has to lower margins to win. The commodity work, where you grab some project engineers and a couple of ROVs on a cheap boat (often IRM related), is clearly going to have all the profit bid away for a long time, whereas construction work still has value even in the downturn; but it entails serious risk and range of competencies that are beyond the realms of dreaming about for the smaller contractors.

This relationship between the rising price of oil and marginal demand for shale verus offshore will make this recovery cycle for offshore different to any other. IRM is important in the short-run, but the fewer wells and pipes laid now will ensure not only is future construction work lower but so to is the installed based. There will clearly be a recovery cycle, demand is above last year’s levels and subsea tree orders are well ahead of 16/17 lows, but there is clearly huge competition at the margin for E&P investment dollars in offshore versus onshore which is a competitive dynamic the offshore industry has never had before.

Random Friday afternoon thought… Borr and McKinsey….

They both can’t be right can they?

From a downbeat McKinsey view on the jackup and floater market:

McKinsey jackup demand 1.0.png

From a recent Borr Drilling presentation:

Borr Jackups business.png

I know you can argue high-end jackups will recover etc… it’s just not a booming market if you have this much uncontracted capacity:

Borr fleet status.png

And maybe you would prefer less analysis like this from McKinsey:

After seeing rig activity stabilize during the first half of 2017, it resumed a declining trajectory in the second half of the year, hitting record low levels (estimated at about 300 units for jackup rigs and 140 for floaters). This will keep downward pressure on day-rates, with the few rigs that are finding new contracts, doing so at a sharp discount to the rates earned prior to the oil price decline (about 25 percent for jackups and about 75 percent for floaters from 2014 levels). This means lower margins for rig owners, even though they have reduced operating costs by around 70 percent since 2014.

Roll the dice!