More evidence this is the offshore “recovery”…

I was going to write this anyway today and then looked at the oil price as I was leaving work… down 2.7% at the time of pixel… The graph above comes from the Dallas Fed blog which makes this salient point and helps explain why:

Given current market prices, U.S. shale production will continue growing this year. Indeed, a recent report by the International Energy Agency highlighted that shale production is likely to be a major driver over the next five years. This does not rule out the possibility of major oil price movements, but it does point to a strong tendency that oil prices will be range bound in the near future.

Read the whole thing. Shale has structurally changed the oil industry and fundamentally changed any realistic scenarios for an “offshore recovery”.

Contrast that with the investment boom in shale: If you want to see how the whole ecosystem of companies and innovation are working in a harmony to make US shale more efficient, deepen the capital base, and thereby work in a virtuous circle then this article from the Houston Chronicle that showcases a GEBH project to turn flared gas into power in the region is a great anecdote:

Baker Hughes is using the Permian Basin in West Texas to debut a fleet of new turbines that use excess natural gas from a drilling site to power hydraulic fracturing equipment — reducing flaring, carbon dioxide emissions, people and equipment in remote locations…

Baker Hughes estimates 500 hydraulic fracturing fleets are deployed in shale basins across the United States and Canada. Most of them are powered by trailer-mounted diesel engines. Each fleet consumes more than 7 million gallons of diesel per year, emits an average of 70,000 metric tons of carbon dioxide and require 700,000 tanker truck loads of diesel supplied to remote sites, according to Baker Hughes.

“Electric frack enables the switch from diesel-driven to electrical-driven pumps powered by modular gas turbine generating units,” Simonelli said. “This alleviates several limiting factors for the operator and the pressure pumping company such as diesel truck logistics, excess gas handling, carbon emissions and the reliability of the pressure pumping operation.”

More capital, greater efficiency, and capital deepening. It is a virtuous circle that increases productivity and economic returns and is the signal for firms to invest more. It is a completely different investment dynamic to the one driving offshore projects at the moment.

Shale productivity.png

The above graph from the IEA makess a point I have made any times here: there is no real cost pressure in shale beyond labour (which will drop in the long run). Shale is all about productivity and cost improvement driven by mass production, something the US economy has as an almost intrinsic quality. The cost improvements in offshore are solely the result of over-capitalised assets earning less than their economic rate of return (i.e. oversupply) and is clearly not sustainable in the long run.

That is why firms with a low cost of capital are vacating fields like the North Sea to firms with a higher cost of capital: one requires steady investment and scale, the other investment is a punt on a shortage and price inflation. [A post for another day will be on how on earth some of these larger investors actually get out of the North Sea.]

This IEA data also tells you why this is the offshore reocvery:

IEA 2019 investment mix.png

The IEA is also forecasting overall spending to increase just 6%. So offshore just isn’t getting investment at the margin that will drive fleet utilisation and expansion. In company accounts this is showing up as depreciation significantly outpacing investment and is a constant across the industry. The economics of offshore are such that profitability is dictated by marginal demand (i.e. that one extra day of utilisation at a higher rate) and this graph shows the industry built a fleet for a far higher level and the only realistic prospect here is for structurally lower profitability. Given the high capital costs of the assets this is going to take a long time for the oversupply to work out.

For manufacturers (i.e. subsea trees) the recession is generally over, although not for Weatherford, but if it floats nothing but a wall of oversupply and below economic pricing and therefore sub economic returns is the logical consequence of this industry structure and market dynamic.

The hope of a massive demand boom kept banks from foreclosing and led hedge funds and other alternative capital providers putting money into assets that were (and are) losing cash but seen as “valuable” in the future. Slowly it is becoming apparent there is no credible path to anything other than liquidation for many companies still in business.

Rates will slowly rise, and so will utilisation levels, but only to economic levels i.e. covering their cost of capital in a perfectly competitive market. Absent a demand boom liquidity slowly, and then quickly, vanishes. And that is finally starting to happen now. For example the McDermott 10.25% 2024 bonds, already very expensive, were trading at well below par today implying a 13.5% yield, in effect locking them out of the unsecured credit market completely (and in reality all credit markets). A restructuring beckons. MDR will not be the only one by any stretch. Many rig companies will do a Chap 22 and a wave of supply companies in Europe and Asia are uneconomic and simply cannot survive under realistic financial assumptions.

Slowly the overcapacity in the industry will work its way out to more economically sustainable day rates with higher utilisation levels in a smaller global offshore rig and vessel fleet. But it won’t be a return to 2013, it will be a return to a far lower profitability level despite the smaller fleet, higher prices, and less time and utilisation risk taken smaller companies. There will be a complete wipe-out, almost without exception, of investors who backed offshore “recovery” theses of asset backed companies and an inability of these companies to access funding almost at any price levels. Theories about assets recovering to values implied by book value will be realised for what they are: a fantasy no serious person could believe.

But a far more rational industry and market will emerge. The only thing that could change the dynamic outlined above is a massive demand boom, and the graphs above show you why that isn’t going to happen.

IEA global upstream investment 2019.png

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:

IMG_0511.JPG

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.

IMG_0512.JPG

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.

Devil take the hindmost…

“They run all away, and cry, ‘the devil take the hindmost’.”

Philaster

You can’t make this up: the above slide from the latest SolstadFarstad results sums up the problem: in putting together 3 companies to create a “world leading OSV company”, before they can even get the first annual report out, they have to admit that one of the three is insolvent and  another of the three has a serious covenant breach. This was always a triumph of hope and complexity over a serious strategy.  Having spent NOK 986m in Q1 to get NOK 875m in revenue, a NOK 469m loss after adding back depreciation, a financial highlight was considered a NOK 12m saving in overhead due to synergies! Personally I would have forgone the NOK 12m in synergies to not have two subsidiaries in default that threatened the entire company’s solvency? You don’t get any sense from the public announcements that anyone has a handle on how serious this is.

If there was any value in it stakeholders might want to have an honest look about what got them to this point? In reality I don’t think it is anything more complicated than wanting to believe something that couldn’t possibly be true: namely that at the back end of 2016 the market would recover in 2017. Not confronting that meant not having to come up with a proper financial structure for this enterprise, but really it meant not having to liquidate Farstad and Deep Sea Supply. But it also means that management and their financial advisers were unable to structure a credible 12 month business plan to be accurately reflected in the transaction documentation. This a serious failure and any realistic plan forward needs to recognise this. Talk of SolstsadFarstad being part of industry consolidation, as anything other than a firesale by the banks, just isn’t serious either.

Prospect theory, an area of behavioural finance that recognises people overweight smaller chances of upside rather than accept losses, and the disposition effect where people hold losing investments for longer than they should, seem apt for the lending banks  and management here as an explanation. But the current plan of getting waivers from the banks and waiting for the market to recover is clearly not a serious plan either.

SolstadFarstad will not survive in its current form. There is absolutely no way the assets are worth NOK 30bn (under any realistic valuation  metric be it cash flow, economic, or asset) and no way that they can ever hope to pay the banks back NOK 28bn, without even worrying about the bondholders. The scale of increase in day rates in a few years time would have to be so extreme it just isn’t credible, and every year day rates stay  low requires you add back the forgone assumptions about their increase on a future year increase. The assets are aging and maintenance costs are going up. SolstadFarstad is like a zombie bank where it has no capital because no one will lend it any money to grow (wisely) but it cannot get any equity because the debt is so high. The only chance of survival would appear to be a massive debt haircut, I don’t know what the number is but I would guess at least NOK 15-18bn, and then to get new equity in and come up with a sensible plan.

However it isn’t just money. I don’t think I have ever seen a major merger go wrong so quickly and then have senior management so blithely unaware about how serious the situation is.  The timing on the Deep Sea/ Solship 3 announcement being just one example. A good study here shows management who look beyond the external environment are more likely to survive significant industry change.

One very simple fact of the environment changing is was made by Subsea 7 recently:

John Evans

Yeah. So, what we’re seeing in the market today is the return to the seasonality we saw five to six years ago where the North Sea was relatively quiet in quarter one and quarter four. It’s really, really straightforward that, you know, the weather conditions are particularly extreme in those periods, and therefore then, clients are not looking for their work to be performed during those periods. During the high point in the market, we work right away through those periods and clients were prepared to pay the additional cost to get their first production online faster. Our aim is that we will see in quarter one and quarter three our active fleets and we’ll be back towards a reasonable level of utilisation in line with previous percentages for active fleet utilisation. But then we expect to see again the corner of sea market going relatively quiet in quarter four. So that’s what we really see and in terms of seasonality for us. [Emphasis added].

SolstadFarstad used to charter ships on a 365 basis. Now it has a large number of vessels that take time risk on some other company’s projects. These vessels are going to have less utilisation than before because 2 of the 4 quarters of a year are quiet. Unless there are very high day rates, which there aren’t, a ship that works 50% of the year is worth less than one that works 100% of the year. SolstadFarstad, Bourbon, Maersk, all these similar vessel owners are dealing with a fundamental change in the market and therefore the economic value of their asset base is dramatically lower given the fixed running costs. SolstadFarstad pretending they can ever make the banks whole in such a situation is absurd. A major restructuring gets closer by the day.

[Book recommentdation: Devil Take the Hindmost: A History of Financial Speculation]

Shale productivity, oil prices, and marginal demand…

The quote above comes from the CFO of NOV Global, Clay Williams, in 2011. Clearly he understood the transformative nature of shale before many (as well as putting it as eloquently as anything I have ever read). The question for a long time for many was when will shale stop getting funded? But actually the shale revolution is beyond quetion now and the real question for offshore in a era of rising prices again is what proportion of new investment is directed to offshore versus onshore? Particularly for asset owners with high fixed running costs, and rates at below cash break-even on an annualised basis, what is likely in the short-term?

One of the reasons shale continued to be funded wasn’t just rising oil prices it is because capital markets in the US are efficient enough to support business models with high rates of productivity improvement even if the payoff is not immediate. This recent presentation from Helmerich & Payne, the largest US land based driller, shows why:

HP Well efficiency.png

H&P are targeting a 40% increase (as a stretch goal) in efficiency/productivity, an outcome that would further rapidly enhance the economics of shale. Not only that they are doing it with an assumption of pricing power for the drilling contractor where a 20% improvement in efficiency in operations for the customer leads to a 33% increase in their prices (15k-20k), and the next 20% increase brings them another 25% (20k-25k). With these sort of possible productivity improvements, and a much shorter payback time, it is hard to see a freeze in capital funding anytime soon, and in fact at current prices the investment boom is self sustaining anyway. This incremental learning-by-doing and constant improvement is a core part of manufacturing efficiency and has become part of the standard DNA of manufacturing companies (for a fascinating look at how this came to be in the car industry read The Machine that Changed the World). Deming would be proud.

Those sort of productivity improvements, on a per barrel delivered equivalent basis, are the competition for offshore production at the margin for project investment decisions. I continue to believe this will favour much larger, high volume, offshore fields over shallow water developments. Offshore faces the hurdle of clong lead times that were previously just assumed as an unavoidable part of the oil basis. A blog post for another day is the insights behavioural economics offers to this.

Pioneer Natural Resources also came out this week talking up their productivity:

Pioneer Improvement.JPG

This data point is interesting and is the crux of future demand across the offshore supply chain:

Shale rigs vs offshore.JPG

That index ratio is really what will drive the strength of any offshore recovery. Since May 16 up until January 18 rising oil prices (much slower than currently) were met with a massive increase in the shale rig count and continued decreasing demand of the offshore rig count. In May 16 the price of WTI was ~$44.00 and Jan 18 the price of WTI ~66.60 so a ~51% increase in the price of oil was followed by a 160% in US land rigs and a 22% reduction in offshore rigs. Any statistical model of industry demand that not have this relationship in the regression is to my mind invalid. Any statistical model without a period break from c. 2014-2016 should similarly be treated with exceptional caution. The future, statistically speaking, will not be like the past.

There are a host of reasons (many covered here previously) but the argument that increasing oil prices will be met at the margin first with an increase in demand for short cycle shale seems irrefutable. Any “offshore recovery” post the shale revolution is clearly going to be very different to recovery cycles prior to this enormous investment and capital deepening process that has taken place in the last 5-7 years.

$60 is the new $100…

There is a boom in oil… it’s just not in Aberdeen or Stavanger…

“$60 is like the new $100,” said Dallas Fed economist Michael Plante in a mid-April interview.

Breakeven costs are now as little as $25 per barrel, according to the Dallas Fed’s most recent survey, so energy companies here no longer need $100 oil to make lots of money…

“It is a full-fledged boom,” says Dale Redman, chief executive of Propetro, a Midland, Texas, firm that supplies heavyduty horsepower to drill sites, where energy companies coax crude from the ground with sand and water.

He has tripled his workforce since early 2016, drawing workers from towns and cities hundreds of miles away. Over half of his 1,200 employees make more than $100,000. “What it has done is raised wages for all these folks. But housing and the cost of living has gone up as well.”

Eventually labour costs will rise, and as they are proportionally more expensive than offshore labour costs due to capital intensity, offshore will become more attractive in investment terms. But that will be offset by a productivity improvement. Never underestimate the ability of the US economy to be an efficient mass producer at scale.

The fallacy of composition and offshore equilibrium…

There is a really eloquent quote from the Hornbeck conference call that I didn’t want to get lost in my other post (courtesy of Seeking Alpha):

James Harp (CFO, Hornbeck Offshore):

The recent rise in commodity prices has led to a generally positive sentiment for the broader oilfield service industry including the offshore sector. But as Todd said we see little that leads us to believe that deep and ultradeepwater exploration will see a sharp rebound in activity in the immediate near-term.

While of course we are encouraged by equity analysts and larger oilfield service companies calling the bottom on this offshore cycle and it is certainly nice to hear major oil companies announcing more deepwater discoveries, FIDs, and FEED studies in our hemisphere. We are still a long way from reaching OSV market equilibrium. There is always a lag effect from when these types of macro sound bites actually result in increased demand for marine transportation and subsea services.

Investment research should be forward looking (my thoughts here), so it’s no surprise there might be a valuation gap between the current price and when cash flows into a company, but it is also true there have been a number of people claiming a market recovery when it doesn’t seem to be reflected in how owners feel? Both might be right: it is a recovery but off a low base and this recovery is miles away from an economic equilibrium. Also some sectors will do well, and others less so, this certainly won’t be a broad recovery.

Everytime a new offshore project, especially a major one, is announced people seem to try and use it to illustrate a turning point in the cycle, despite the fact that the macro numbers are clear: investment is way down from 2014 and the number of working rigs/ jackups etc is so low that anything other than a slow recovery is unlikely. This is the fallacy of composition: inferring the whole is true based on a small part of it being true.

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.