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.

 

 

How much is the Lewek Constellation worth? Somewhere between USD 43m and USD 370m (I’m closer to the former)…

“His services are like so many white elephants, of which nobody can make use, and yet that drain one’s gratitude, if indeed one does not feel bankrupt.”

G. E. Jewbury’s Letters, 1892

The EMAS Chiyoda restructuring plan nears execution. The most interesting aspect to me is what the Lewek Constellation is valued at and how the banks get this problem off their hands (i.e. how much of a loss do they have to take?) Outside of Saipem, SS7, Technip, McDermott, and Heerema (maybe) it is very hard to see who the realistic buyers would be? There is no spot market for these assets because you need a huge engineering capability (and cost base) on the beach to run one of these assets. And the real problem is that all these potential buyers have added substantial new tonnage in deepwater pipelay very recently. (My previous thoughts on asset specificity and transaction costs are here). Without a dramatic improvement in the market it’s hard to see why anyone would want this asset?

Or not? In the Chapter 11 reorg Subsea 7 and Chiyoda are essentially providing a USD 90m Debtor-In-Possession  facility that sees them take over 5 EMAS Chiyoda entities emerge that have 15 projects with c.1bn in backlog. Subsea 7 obviously decided this was the easiest way to get the work, and when you drop c.USD 1bn in backlog in a year it’s easy to see why you want to be inventive. The big SURF scopes are Cape Three Points and Chevron Tahiti Vertical Expansion. Given how far the engineering had advanced and the fact the contracts had been awarded it is easy to see why Subsea 7 would want to take some risk getting this work.

Some context: back in 2013, the build year of the Lewek Constellation, Clarkson published this graph:

Clarkson Subsea Trees Nov 25 2013

Now Clarkson’s are no different to anyone. I could have picked any number of information providers, the commonly held view was only how much growth there would be, and how much kit you needed to access it. Shale was not in vogue and starting it’s extraordinary journey.  Although as an aside, because I don’t want to delve into shale productivity here (but you can read some of my thoughts here and here), the US rig count was higher than it currently is.  But the point is clearly that boards, managers, and financing institutions all thought the market would evolve something like that graph. On such a basis the investment decision was made for the Lewek Constellation and DNB and a syndicate of banks advanced USD 503m in two facilities and got two Panamian mortgages and a credit agreement in return. Of that USD 370m in capital is outstanding under facuility A (and the 100m from facility B is effectively written off) in the Chap 11.

The market has obviously changed somewhat:

Subsea Tree Awards 2000-2019e

The single best indicator of future demand for heavy installation vessels is subsea tree awards. Now it is clear that demand has dropped and will remain depressed for a long time at around 2003/2004 levels. Strip out Brazil, where Petrobras has extensive spare PLSV capacity for flexlay, and you are within a margin of error of 2003 numbers. Yes, more proportionately will be in deep water, but the subsea lay fleet was built for 2013/14 not 2003 and no amount of deferred consideration can change that.

Let’s be clear the Lewek Constellation is a capable vessel, but I wrote here about competition: a significant number of competing vessels have been built in recent years and this is all about competition at the margin. These types of vessels don’t work to their maximum potential every day, they work on a broad range of smaller jobs and then make real money on a couple of jobs of a year where the competition is less and pricing is based not only on vessel capability but about engineering value added by the contractor. None of them is differentiated enough to win a project in its own right.

So a market transaction has been reached whereby Newco (owned by Subsea 7) will charter the vessel for USD 4.3m per annum and the cost of the dry dock (c. 2018) is split 50/50 at ~USD 5m each. That is, in the current environment Subsea 7/Newco judges that it is economic to add marginal (extra) lay capacity at bareboat rate per year of USD 4.3m, plus drydock accrual and operating expenses,  and the bank/owner has agreed it is economic to charter their asset at this rate. That is a market-based economic transaction between a “willing-buyer/ willing-seller” for the capital value of the asset and it reflects some backlog that a qualified purchaser can deliver with it. Subsea 7/Newco has an option to purchase the asset for USD 370m during the first 2 years of the charter agreement and this is then used a “floor” going forward or broker valuations less USD 20m. The extension options rise dramatically (see below).

Now if you add 3% per annum to the charter rate, add in dry dock costs, assume 10m salvage value in 20 years, and discount this back by the DNB WACC (10.4% today) you get an implied vessel value of ~ USD 43m.  I would argue that is a fair value for the vessel, which is pretty much in line with the discount MDR paid for the Amazon and NPCC paid for Atlantis (I mentioned this yesterday).  [I used the 3% growth in the annual day rate to reflect an industry with excess capacity and therefore growth roughly inline or above a CPI measure, obviously the mortgage banks would regard this number as unacceptably low. However, I think the discount rate at DNB WACC (rather than funding costs or liquidity spreads perhaps) given the project risk is far too low. Obviously different inputs will lead to different results.] For the sake of a comparison in order to get the vessel value to anything like USD 370m you have to increase the charter rate 25% per annum for the entire assumed 20 year period! The charter rate is also linked to a LIBOR adjustment, something that is very rare, and highlights how senstive the banks are to a valuation projection here.

This purchase option number strikes me as a fantasy and reflects the fact that DNB recorded a capital value of USD 370m outstanding in the Chap 11 filing. If you look at the forward order book for subsea trees or announced projects in three years, and all the excess capacity on the vessels, who really believes Subsea 7 is going to pay USD 60 000 per day in 4 years time (USD 21.9m per annum) rising to USD 80 000 per day (USD 29m per annum) in 5 years time? You might do under the assumptions in the first graph but not in the second. It is a chimera to help the banks out and allow everyone to play for time. The initial charter rate implies a 1.16% interest rate on the capital outstanding, so DNB don’t really believe the USD 370m figure, but it highlights the size of the economic subsidy required now for everyone to pretend they haven’t lost as much money as they say.

I was a big fan of Subsea 7 just handing the asset back and forcing the banks into a lengthy period of nervousness and reality, but it would have meant Subsea having to tender for the work. I believe that the Lewek Constellation is such a specific asset that it is actually effectively valueless in the current market. The best thing for the industry was for the asset to fade into obscurity; in this market, and after Ceona, no one would risk a start-up and few other companies would have agreed to help DNB. Clearly Subsea 7 have a strong cash and liquidity position, need the work, and this gives them an option if the market really did take off again. However, surely the most likely scenario from the banks point-of-view, under any objective reading of the market, is that in two years Subsea 7 come back and tell them to start getting real about the price and the asset value? There is a very Norwegian behind the scenes solution going on here with DNB obviously desperate not to have to recognise the vessel at a fire sale price now, or expose itself to the OpEx, and in all likelihood was involved in soliciting Subsea 7 as part of the financing shop around discussed in the documents.

If the Bibby bondholders are looking at these transactions closely they must be getting nervous now. With the bonds trading in the mid-60s the implied valuation of the Polaris and Sapphire is c.GBP 105m, a number that looks as egregious as the USD 370m purchase option for the Lewek Constellation.

The big risk for Subsea 7 isn’t the committed expenditure, which amounts to USD 4.3m for charter per annum (+ the undefined LIBOR spread), + vessel OpEx (probably the same), and c. USD 5m for the dry-dock, it is that they appear to have agreed to deliver the EMAS Chiyoda contracts for the same lump sum price and contractual terms. The few projects EMAS Chiyoda delivered were a disaster in engineering terms, and that isn’t just Angostura, I have spoken to people who have managed other jobs with them. If Subsea 7 haven’t had enough time to due diligence the project engineering and costing properly, which is notoriously hard in lump sum jobs, they are going to have a big problem. Although the contracts appear to be novated to Newco, who exposure in one set of documents appears capped at USD 90m (that may be a placeholder), such a situation is likely to involve other Subsea 7 tonnage and exposure through the supply chain. Subsea 7 are one of the world’s great engineering houses but in 2013 a painful conference call to discuss Guara Lula (which they had bid themselves) led to these comments:

[w]e moved into the offshore phase of the project in the second quarter, with the Seven Polaris and the Seven Oceans being deployed on location. We are experiencing more weather downtime than originally planned due to severe weather conditions in the Santos Basin during the Brazilian winter. We have suffered equipment damage and the resulting downtime on the Polaris due to this bad weather. We expect these conditions to continue until the season is over. Although we are contractually covered for time spent by the prime vessel waiting on weather, we incur additional costs, both offshore and onshore, which are not covered. In addition, we have taken a more cautious approach in evaluating what can be achieved offshore during periods of calm weather, in view of the complexity of the facts involved…

Second, the stretched supply chain is resulting in delays from international and local suppliers….

[t]here was a delayed start to pipeline fabrication at the Ubu spool-base largely due to customs clearance issues. Initial productivity at Ubu has also taken longer to ramp up than expected…

A re-evaluation of the offshore risks based on experience to date, and the extended timeline of the project, has resulted in us increasing the estimate full-life project loss by between $250 and $300 million.

Final losses were USD 355m and that was on vessels and a project they tendered internally. Subsea 7 don’t know this vessel at all, and the engineers and tendering staff had all been instructed to win these tenders at all costs having spoken to people involved in tendering at that stage for EMAS. It may not happen, and they may have done sufficient due diligence, but when you agree to go basically lump sum you are taking execution risk on a tender and asset outside of your management system. Don’t complain later you couldn’t have forseen it, but backlog looks like it is going down so fast they may feel they have few options.

At some point the industry (contractors and financing institutions) are going to have to accept that if all this tonnage remains in operation, and the operating costs are included, then it will have a structural profitability issue without a dramatic change in demand that just isn’t occuring. Yes the Lewek Constellation is a flexible asset, and it can save a variety of vessels working in the field, but those vessels exist now, amongst the current contractors. If an E&P company really wants this specific vessel because of its advantages let them buy it? It only looks more “efficient” in the field compared to other vessels because it isn’t being compared to the historic investments currently solvent contractors have made in a fleet of vessels that collectively perform the same function.

Maybe Subea 7 are looking to retire some older tonnage later on and the easiest way to get over a difficult discussion with the banks was to kick the problem into touch? But at some point the discussion will have to come and I would have thought the banks auditors would have forced it now because in a default situation the value of the vessel is very clear: about USD 43m on a standard capitalised valuation framework. Convincing the auditor that in 36 months you will get a 6x uplift in the day rate when the market forecast is for negligible growth and stable supply strikes me as unlikely in the extreme.

The amount of offshore work may have hit its bottom level and some good contracts are being awarded, but as Eidesvik reminded us today more restructurings are coming, Solutions like this which simply push the eventual reduction in asset values further into the distance will only ensure continued weak profitability for vessel owners (and banks).

Shell and Bourbon: a tale of two cities

“In short,” said Sydney, “this is a desperate time, when desperate games are played for desperate stakes.” 

A Tale of Two Cities

Despite oil prices remaining above US$50 a barrel during the 1st quarter of 2017, activity is yet to recover in the Shallow water offshore and Deepwater offshore sectors”

Jacques de Chateauvieux, Chairman and Chief Executive Officer of BOURBON Corporation.

I am absolutely not going to turn this blog into one that goes through the financial results every quarter (and even less so one that follows the oil price), but I do think now is an interesting time because on a volume basis they make up a large percentage of the total offshore CapEx so their spending plans are important. The most important forward number the contracting community needs to focus on is backlog, for the simple reason that in volume terms it drives the number of days utilisation. Shell reported today as did Bourbon, and I believe that they support the view I have taken here and here with BP: we are looking at a structural change in the offshore contracting industry and the likelihood of a supply crunch saviour is unlikely at best.

The massive supply crunch that the IEA forecasts doesn’t appear to be showing up in the physical market (with oil down nearly 5% today although I believe daily prices are a close to a random variable) or the futures market. This IEA forecast is starting to look chimerical:

Global oil supply may struggle to match demand after 2020, when the pinch of a two-year decline in investment in new production could leave spare capacity at a 14-year low and send prices sharply higher, the International Energy Agency said on Monday.

Investors generally are not betting on a sharp rise in the price of crude oil any time soon, but the contraction in global spending in 2015 and 2016 and growing global demand means the world could well face a “supply crunch” if new projects are not soon given the go-ahead, the IEA said in its five-year “Oil 2017” market analysis and forecast report

Firstly the Shell numbers: unsurprisingly there was a massive growth in profit as the oil price went straight to the bootom line. Like BP its all about the CapEx and the dividends:

Shell Dividends

Despite a massive drop in earnings Shell sells stuff and borrows more to pay shareholders the same. And like BP it will massively cut back CapEx compared to historic periods:

Shell Capex.png

The cut from 2013 to 2016 is nigh on 50% for upstream, It is also worth looking at the drop in Europe. Yes, Shell sold a large proportion of the portfolio to Chryosoar, but from a market perspective it will take the new company some time to develop and execute its plans, and there is more chance than not that they take more time to develop as a new management team and shareholder base come to grips with the scale of what they have purchased and match their asset to their strategic plans. Some quick wins maybe, huge CapEx developments… Unlikely. For European contractors that is bad news.

Shell also made plain in their strategy presentation last year that:

Capital investment will be in the range of $25-$30 billion each year to 2020, as we improve capital efficiency and ensure a more predictable development funnel for new projects. Investment for 2016 is expected to be $29 billion, excluding the purchase price of BG, some 35% lower than the pro-forma Shell-plus-BG level in 2014. In the prevailing low oil price environment we will continue to drive capital spending down towards the bottom end of this range; or even lower if needed. In a higher oil price future we intend to cap our spending at the top end of the range.

As I said I believe their shareholders have made clear the dividend is sacrosanct and the management get it. This is what economists call a time consistency issue, and in this case the incentive to keep the commitment is the same as the incentive to make the commitment. In other words, they are likely to keep this promise because everyone is incentivised just to take the money if oil prices suddenly shoot up.

Shell also noted geographically their commitment to deepwater:

Brazil and the Gulf of Mexico represent the best real estate in global deep water. We are developing competitive projects here based on this advantaged acreage. Shell’s deep-water production could double, to some 900 thousand barrels of oil equivalent per day (kboed) in 2020, compared with 450 kboed in 2015.

The fact is that operating costs are lower in these regions compared to the North Sea: e.g. PSV runs have lower spec vessels, cheaper fuel, cheaper crews, and lower CapEx. It’s all about driving unit production costs down now, just like a manufacturing business every process will be examined and reviewed and an attempt made to lower the cost.

To that end Shell have approved the Kaiskias development for a 40 000 bpd field (them picture here). Like BP on Mad Dog Phase 2 Shell got a near 50% reduction in development costs and replicated previous design knowledge. These companies are using large offshore projects as the baseload for their production needs and building shale capability as the marginal production that flexs as market needs dictate.

And shale is flexible:  the Baker Hughes rig count hit 697 rigs last week, up 9 on the last week, but up an astonishing 365 year-on-year (91%). It’s just the right growth rate, not so high cost goes mad, but high enough to substantially affect the market price and keep investment incoming. Goldilocks growth. Right now those rig and service companies are adding more capacity, training more people, learning how they can extract more per well, and lower the running cost. Every day they learn more and apply more in a self referential cycle that is the hallmark of standardisation and lowering unit costs. Bet against it at your peril.

The other side of this production revolution could been seen as Bourbon also reported today. Revenue down 28% year-on-year! Bourbon is so big it is a bellweather for those exposed to assets without the project execution capability that others have. The contrast with Shell couldn’t be more obvious. Poor utilisation and management highlighting only they had negotiated with ICBC to taper lease payments. There is no light at the moment for subsea – which is consistent with what GE said this week. The common theme here is that subsea is structurally unattractive compared to other development opportunities. High upfront exploration and appraisal costs relative to flow rates make it harder to attract upfront funding and capacity utilisation at below economic levels for vessel operators still not lowering costs enough to bring the market into equilibrium.

You don’t need to run a regression to understand what is happening here: investment is pouring into shale and ignoring offshore for all but the most certain bets. Until CapEx from the E&P companies comes back any hope of a “recovery” for those long on tonnage is a mirage. CapEx drives utilisation in a way IRM just cannot. At some point the offshore community is going to have to stop pretending the only possible solution here is a market “recovery”. There has been a fundamental and structural change in the market. Multi-year commitment to low CapEx is not what the global fleet was built for, it was built for 2013 when Shell Upstream alone chucked a cheeky USD 24bn at improving production, not a measly USD 12bn per annum capped.

I think this highlights what a massive mistake Solstad has made here by taking on Farstad and DeepSea. A supplier of high-end CSVs may have had an independent future, but exposing yourself to commodity tonnage, predominantly in structurally unattractive regions suffering declining investment, without enough scale to generate pricing power, is looking more and more like a poor move every day (not that it ever looked good). Minorities in Solstad must be livid.

Clearly those contractors who can deliver large offshore projects in deepwater have a viable business model if they don’t have too much tonnage. For the rest it will be years of sub-economic returns unless restructuring brings a new capital structure.

BP results, the future of offshore, and myopic loss aversion…

The myopic loss aversion explanation rests on two behavioral principles: loss aversion and mental accounting. Loss aversion re-fers to the fact that people tend to be more sensitive to decreases in their wealth than to increases.

Thaler, Tversky, Kahneman, and Schwartz (The Quarterly Journal of Economics, 1997

 

Let me start by saying, as I have many times before, I am a believer in offshore oil and gas production. My issue at the moment isn’t that it is going to go away, rather it is that too many vessels have been built, and that 2012-2014 was a peak bubble of activity. There will still be good money to be made offshore, I am just not sure it will be through owning vessels (and rigs) until a very painful, and in all likelihood prolonged, restructuring process has been completed.

I recently wrote my thoughts on economic research and dividend policy and why this may lead to an undersupply of offshore projects in the future. I am not conviced this will happen at all, but it seems to be the great hope for all involved in offshore. The BP results yesterday highlight what I was saying with one perfect graph:

BP Cash vs Capex 17Q1

For BP the dividend doesn’t change, CapEx, the driver of future production and profitability potential, is the moveable number. And in a large corporation it is surprisingly flexible in the short-term. (“A billion here, a billion there, pretty soon you are talking real money…”). I think this is typical of all the supermajors, their shareholders want dividends.  The data reveal that Shell and BP alone were responsible in Q1 2017 for £4.8bn of the total £12.5bn (38%!!) of total FTSE 100 dividends. BP and Shell shareholders, UK pension funds especially, want the money now not the hypothetical billions available from a shortage of capacity in a few years time.

Another way to look at it is this: the BP dividend was USD 10.0 cents per share in Q1 2017, and Q4 2016, but this is way more than the company is earning per share (bold Q1 2017, then Q4 2016, then Q1 2016):

BP EPS Q12017

BP is making up the numbers by increasing the debt and divestments in the portfolio. The last thing they want, and their shareholders I suspect, is a large and capital intensive bet on risky offshore projects. As if to reassure everyone this is the case the CFO gave look ahead guidance for CapEx at these levels until 2021.

There is a really good interview with Starlee Sykes, BP VP Global Projects, that is well worth a read – the cost on the Mad Dog phase 2 project was cut to USD 9bn (from USD 20bn). Several parts struck me but none more than this:

We looked for analogies to what we had done before and focused on the Atlantis project in the gulf, which came online in 2007, and its semisubmersible-platform design concept. Atlantis was, and is, viewed as a very economic, very good development. We decided to adopt this simpler design concept. Compared to the original Mad Dog 2 stacked-deck spar design, the semisubmersible is flexible for building future capacity, while fulfilling minimum technical requirements. That was the big idea around Mad Dog 2. Rather than designing for a future that may not happen, the principle was to build what we need at day one, and then allow for the expansion later. So, for example, we did not install all of the water-injection capacity that we needed on day one. It’s a more incremental approach.

A total change of mindset for the industry where everything in offshore was bespoke and future proof. This is part of a slow path to standardisation where possible to reduce costs. Mad Dog Phase 2 can produce 140 000 bpd at peak capacity, far beyond anything tight oil can dream of. At that level, and with efficient lift costs, it’s well worthwhile dropping a cool USD 9bn. But as I have said before I see offshore bifurcating into developments like this with very high flow rates and very high CapEx commitments, normally at deepwater, (only the Norwegians seem to get lucky enough to find huge fields at shallow depths now), and a base of demand in Asia and the Middle East where NOC’s are more security supply focused where they will develop in shallow (often alone) as well as deeper water (where they will need a supermajor partner for technical expertise).

I fear for the shallow UKCS which is somewhat caught in the middle: SPS technology isn’t standardised and cannot feel the effects of scale and scope that tight oil has, yet these fields cannot provide the reserve capacity in a high cost environment. One of the reasons the Norwegian basin seems to do better than the UKCS is an understanding of Loss Aversion Theory, that in essence states that investors would rather not lose $5 than gain $5: in Norway tax incentives for drilling are heavily front ended loaded versus credits for production in the UK (making a massive generalisation of a very complex issue). A classic article on myopia and and loss aversion in risk taking is available here. Which is a lot like shareholders in E&P companies who have seen paper wealth vanish as the oil price drops.

To be effective shallow offshore fields will have to be subject to some form of standardisation around production equipment and SURF installation, and we are a long way from that at the moment because a core component of that is drop volume which drives the experience curve. And of course as the E&P companies cut CapEx, that is distinctly lacking.

The other problem offshore has at the moment is management focus and resource constraints. I have mentioned before the power of narrative in economics, as Shiller argues:

[w]e have to consider the possibility that sometimes the dominant reason why a recession is severe is related to the prevalence and vividness of certain stories, not the purely economic feedback or multipliers that economists love to model.

The industry meme at the moment is all about cost and tight oil. Changing that mindset in large organisations is hard – it can take at least 12 months if peoples bonuses have just been contractually set for exmaple and they are based on cost savings. A recovery for the offshore contracting industry is going to rely on changing this narrative somewhat.

I have discussed here mainly the demand side of the market which I believe will be structurally more unattractive for the next few years going forward. I still think for the supply side, the offshore contractors, there can be a bright future if positioned clearly: a tight fleet of core enabling assets (mainly lay capability) and a strong EPIC competency, and an ability to position the firm to respond to this structural change in the industry.

I am generally sceptical on alliances and integration between SPS and SURF because I think they add more  value to the contractor than customer, and as Exxon Mobil showed with the Liza award, an educated customer can drive the price down by splitting workscopes. But I am writing a fuller piece on this.

Low order backlog defines and highlights lack of current subsea recovery

Three companies that define the subsea industry reported numbers this week: Saipem, TechnipFMC (imagine if they had brought CGG!), and Subsea 7. All were widely varying but the clear theme of overcapacity/ underutilisation remains with subtle variations. Clearly the place to be if possible is light on core assets and long on engineering and execution capability if possible. The core question for the subsea industry remains what proportion of oil demand will be met by offshore production fields (and to a certain extent what the growth of overall demand will be)?

On future market demand the IEA was in the press again today with this:

Less than 5 billion barrels’ worth of conventional oil resources were sanctioned for development last year, down from almost 7 billion barrels in 2015 and 21 billion barrels in 2014, the year oil prices began their slide. Approvals of offshore projects, which are typically more expensive, fell disproportionately, representing 14 per cent of new project sanctions compared with more than 40 per cent on average over the previous 15 years.

Spending on exploration is on course to fall again for the third year running, the IEA said, reducing it to less than half the level seen in 2014, when it stood at more than $120 billion (£92.9 billion).

I have said here before I don’t see offshore production going away. Offshore will clearly continue to be a crucial part of the energy mix. The question, as always, is how much share as the vessel fleet has been built for a far bigger proportion than is currently being demanded. I heard repeated again last week that underinvestment in the current cycle makes a snap back “inevitable” and when this happens offshore will boom again. I’m just not sure I agree as the supply side seems to be out of all proportion to the market and the working capital subsea companies need who are too long on vessels may make the gap too long to bridge given how long it takes for projects to roll out post FID.

While the IEA warns of the this investment crunch Spencer Dale, Chief Economist at BP, is far more sanguine. I quote this speech all the time but its worth requoting a core point:

The US shale revolution has, in effect, introduced a kink in the (short-run) oil supply curve, which should act to dampen price volatility. As prices fall, the supply of shale oil will decline, mitigating the fall in oil prices.

Likewise, as prices recover, shale oil will increase, limiting any spike in oil prices.

Shale oil acts as a form of shock absorber for the global oil market…

To be clear: shale oil is the marginal source of supply only in a temporal sense. The majority of shale oil lies somewhere in the middle of the cost curve. As such, further out, as other types of production have time to adjust and oil companies have to take account of the cost of investing in new drilling rigs and operating platforms, the burden of adjustment is likely to shift gradually away from shale oil towards other forms of production, further up the cost curve.

 

(Emphasis added).

This was written in 2015 and its obvious now that this is exactly what has happened. The sceptic in me struggles with the core logic that rational economic actors are prepared to forgo potentially huge sums by not investing now. If this was such a slam dunk case as the IEA make out then why don’t some smart private equity firms partner with big oil (for the technical skills) and simply develop these fields, when construction costs are at an all-time low? The answer is because it isn’t that simple I suspect.

I am basically a weak-form efficiency believer. I think the oil market is largely rational in the long-run. The long run is a sufficiently amorphous and indeterminate period of time to say that at certain times it can be “irrational” (i.e. USD 27 was to low, but USD 130 was too high), but on average it helps demand and supply meet. But I do realise that one of the problems in the oil market is that many investors in their equity buy them as a dividend stock. Despite the fact that the underlying commodity is extremely volatile in short term pricing (and is likely to be a random walk in anything other than a 1-2 year period), and that therefore E&P companies should really pay out dividends as a proportion of earnings, they quite simply don’t. To E&P companies the dividend is regarded as sacrosanct. Financial economists know this phenomenan well and its formal definition comes in the “Bird in the hand” dividend theory or the “Dividend Clientele Hypothesis“. BIH argues that investors prefer the certainty of dividends to future capital gains and the DCH argues that certain types of investors favour companies that pay dividends (often because of tax or investment mandates). I think they are both right and that the supermajor shareholders in the main are made up of these types of investors.

This means that E&P companies would forgo likely payoffs in the future to keep shareholders happy now (especially as they could fund future CapEx from higher future prices). So I get this could this be happening. And the downside of course is that if you are wrong, and you have made a superbet on this market shortfall in 2020 (or whenever), you end up with a 25 year asset in (e.g.) offshore Brazil that cost USD 3-5bn that you can’t shut down or exit easily that is producing 100 000 bpd at a cost greater than their economic value. Clearly these sort of risk probably work better as part of a portfolio play and hence why the super majors exist: they are an economically rational response to the market issues.

It’s within this context that the results of these offshore contractors need to be seen. The common theme across the industry is that backlog is not returning as quickly as offshore contractors are burning through current work. The other common theme I think is a flight to quality where E&P companies are engaging with tier 1 contractors more and the smaller players will find it increasingly hard. Smaller E&P players Technip and Subsea 7 would never have bothered to court are flattered when they are pursued by these companies offering them the full suite of their capabilities and assets.

Subsea 7 came in with really good EBITDA numbers; but they had the benefit of delivering projects bid at higher margins while procurement is being done at a low point in the cycle. But the other thing Subsea 7 has done really well is utilisation: with fixed vessel costs so high any extra days drop straight to the bottom line. Active utilisation of 65% for their fleet is exceptional in this market (compare to Oympic). I have no idea if this is an apocrophyl story or not but I was told a year or so ago that Kristian Siem instructed Subsea 7 management that he personally has to sign off on all vessel charters using third-party tonnage now, to encourage projects crews to use a Subsea 7 or Siem vessel. Even if its not true I think the mindset is and it fits in with what all the line managers are saying about Subsea 7 in the market: they are extremely aggressive on vessel days (for example remving the Pelican from cold stack for Apache in the North Sea). Don’t get me wrong it’s smart and necessary: Subsea 7, with 34 vessels, just have to get them working or they will have a credit event, and its good execution.

But the Seven Mar and the Seven Navica are in still in cold stack. The Navica in particular is a talisman for North Sea construction activity. Until that vessel is busy doing small scale field developments then by definition the North Sea (an UKCS in particular) will be oversupplied with DSVs and overly dependent on maintenance rather than construction work. The fact that these assets are in cold stack (and it’s not only Subsea 7) means there is an enormous amount of latent capacity in the sysytem that could respond to increased E&P demand very quickly. Portable lay spreads and ad-hoc systems (like the one on the Bibby Polaris) have also grown in number in recent years and could be quickly activated.

Saipem also came in with a poor order book at 0.2x book-to-bill (i.e. it replaced 20% of the revenue billed this quarter with new work). It can overshadow the fact that Saipem is still a really big company with an annual turnover of 10bn, a great franchise in some very difficult regions (which make it less margin sensitive), and a wealth of technical expertise. But the problem Saipem has is that it is an average drilling company and a quality subsea/ pipeline company. All the drilling companies are restructuring and coming back with very strong balance sheets for the next few years and Saipem has some major drilling contract renewals next year and its not hard to see revenue dropping like a stone in that business. Having raised €3.5bn in a rights issue Saipem then had to go back and write €2.1bn off (non cash), but it is trying to pay back its lenders 100c in € whereas all their competitors are engaged in debt-for-equity swaps. It’s totally unsustainable. Not like EZRA where it was obviously going to happen near term, this is a slow battle of attrition as more and more time and equity gets devoted to the Sisyphian task of trying to generate economic value with an overvalued asset base (in a relartive sense) that has a higher fixed cost base.

Which is a shame because the Saipem offshore construction business, with a fleet of quality assets, an eviable project track record, and huge intellectual capital, despite being buried in a Byzantine organisational structure, is a great business. With the right balance sheet and strategic direction the Saipem Offshore E&C business could be a world leader, it is long all the assets you can’t possibly charter (nor would you want to), such as heavylift and and pipelay (J and S), and long on engineering capability. Every other subsea asset you can be short on at the moment because the vessel market is oversupplied and will be for a long time. Even diving for shallow water construction can be handled internally with chartered tonnage.

There is no real resolution here. Saipem is reorganising (again).  But I doubt you could could realistically seperate out the different divisions in an equitable way from a capital markets perspective. From a subsea perspective the remaining three business lines (onshore and offshore drilling) will just detract from the potential of what should be a tier 1 powerhouse (even if it does make the Italian post office look efficient).

Which brings us on nicely to TechnipFMC… low order book in Subsea while reasonably good numbers. It is the industry bellweather at the moment, no one can do in deepwater what they can, and if they cannot replace their orderbook  the total addressable market will be smaller.

I’m clearly no expert on the oil market but it is clear that offshore investment does not appear to have stabilised yet. Until the core companies in the industry have reasonable amounts of backlog it is too early to talk of a recovery. And the IEA may be right that we are currently underinvesting, but for offshore the key is the snapback: if it comes, it is likely to be less dramatic for anyone who is too long on vessel capacity, but for those with delivery capability and intellectual property it is a different story.

The Carnegie Triple, Transaction Costs, and offshore economics

Any problem that can be posed directly or indirectly as a contracting problem is usefully investigated in transaction cost economizing terms…

Williamson, 1985

From my earliest involvement in the offshore industry, the framing device I have always looked at to understand issues is transaction cost economics, a branch of economics that originated in the seemingly mundane question “Why are firms different?”. The question sounds innocuous because it seems so obvious that they are, but neo-classical economics, in particular, sought to argue that all humans are rational actors, and therefore if they all saw the same opportunities all firms would make the same decisions, and the world would be awash with homogenous firms and products, all priced at the same level: utopian perfect competition.

Of course, the world isn’t like that, blatantly there are many different firms and business models, all supplying similar products. The first person to really tackle this (although this is a little unfair on Knight) was Ronald Coase, who earned himself a Nobel prize for the privilege of putting forth an argument based on transaction costs economics (“TCE”): simply put if it was cheaper for the firm to do something internally it would do it, if it was more expensive it would outsource. This might seem tautological now but in 1937 it was a serious advance in knowledge and the full article is an exercise in eloquence an insight that my few words can not do justice to here.  The field was later developed further, by interdisciplinary scholars, particularly Oliver Williamson, who gives a very good introduction here (and I especially like the Carnegie Triple as a philosophy.)

The reason it is so relevant to offshore is because a large part of the contribution in transaction costs research came from legal scholars:

The study of governance also appeals to bounded rationality, but the main lesson for the science of contract is different: all complex contracts are unavoidably incomplete, on which account the parties will be confronted with the need to adapt to unanticipated disturbances that arise by reason of gaps, errors, and omissions in the original contract.

Williamson, 2007 (emphasis added)

The above is torturously obvious to anyone who has sat through a project engineer and an opposing client rep trying to explain why the other is to blame for a project overrun.

Asset specificity, which I often mention here has its origins in Coase and Williamson:

Williamson (1975, 1985, 1986) argued that transaction-specific assets are non-redeployable physical and human investments that are specialized and unique to a task…

Like diving or pipelay for example… I was always fascinated that there was a spot market for DSVs in Asia, but not one in the North Sea? Another intriguing conundrum was why Toisa only chartered DSVs by Bibby and others were saturation dive contractors? Offshore construction and maintenance is a contracting business, it involves agency issues and internal organisation questions about efficiency because of its short-and-long run nature. It is almost the perfect textbook example to delve into to understand industrial organisation.

But I digress… the big one that got me was pipelay. Every single company with a pipelay spread was fully vertically integrated and there is no spot market for pipelay vessels (the same isn’t true for barges and work that can be done with a modular spread that were far less common in 2005). And then I started to negotiate a JV between a DSV company and a pipelay company… On paper a good idea between two companies, one turns up and drops the pipe and the other turns up and ties it in… everyone goes home for tea and biscuits after making a ton of money: the DSV company can avoid shelling out on a pipelay vessel it knows nothing about, and the pipelay company can save themselves $120m (in those days) on a DSV…

In theory sound. But the problem comes when you look at the actual costs and coordination problems (where inefficiency in knowledge lowers returns to everyone participating). What happens if the pipelay vessel is late to the worksite? What happens if it lays at a slower speed than budgeted (yet all construction jobs are lump-sum)? What happens if they buckle the pipe? And the same set of issues worry the pipelay guys about the DSV… what happens if the bell-runs are too slow? What happens if they are late and the joint bid suffers from liquidated damages? If they damage the pipe who pays for the pipelay vessel to return and lay the new pipe? The beauty of transaction cost theory is it recognises that if you wanted to you could solve all these problems contractually. But on a risk-weighted basis it is simply easier to internalise these and other coordination issues and make them one firm. It is simply a more efficient form of organisation and both customers and shareholders are happier. Hence Subsea 7, Technip, McDermott, Saipem, and briefly EMAS Chiyoda, were all long the assets that made up the majority of the value of a construction job and brought in DSVs at the margin. They either owned them or just contracted them in. (There is another theory about why business models coalesce buried in institutional theory but I’ll save that for another day).

 

Williamson made a major contribution as well through what he calls “the fundamental transformation”. Space precludes a deep discussion about this, but essentially he argues that there is a change from “thick markets” at contract selection (i.e. lots of choice) to “bilateral dependency” at contract execution. If ever an idea summed up the implicit nature of the complexity of an offshore project to me this is it. I am no disciple of Williamson, I am not sure he and the Great Man would have agreed on a lot, but in the offshore construction industry, he has described it perfectly.

I am constantly reminded of this at the moment because in an industry downturn people are trying to put together solutions that are not economically efficient but operationally can be done. Yes, all the problems can be solved with all manner of subcontractors, suppliers, and different vessels, but really, is it needed? Is is sustainable?

A good example, and I need to stop going on about it, is EMAS Chiyoda and the Lewek ExpressI wrote here about why I don’t think there is a long-term solution other than a liquidation, but to add to this point is that even in addition to the capital issues (which are vast an insurmountable) one of the problems is the owners (lenders) of that vessel are either in for a full contracting company or nothing. There is no charter market for the Lewek Express. No one contracts with an oil company to deliver 20″ pipe at 2000m meters below sea level and then hires the vessel in with all the attendant risks (only a few I have mentioned above for demonstration purposes). It’s not that it’s just not sensible it’s not even sane!

The banks/lenders can’t hope that they grab a few of these vessels and park them up at Loyang and charter them out to other contractors for a few hundred thousand a day to cover their costs until the market picks up. There is no market for these assets on a charter basis, even if the other contractors were short on capacity (which they are not). And unlike CDOs from a mortgage market crash the OpEx/CapEx ratio is painful in the extreme.

So the banks and other creditors either fund a fully new offshore contractor or they sell the assets at a loss. You can’t be half pregnant, and you can’t charter a ship when no one wants to charter one, or the only people who will logic would argue are going to lose money. Unless of course you do it so cheaply it is cheaper for them to do it externally, but that rate will be so low only the other party will win (this is an asymmetric information problem and won Akerlof a Nobel prize for used cars and lemons) which is self-defeating.

Subsea 7 has a market cap of c. 5.2bn, McDermott 1.6bn, Sapiem 4.0bn. You get the idea. The banks and lenders are either funding a new EZRA/EMAS to compete against these types of companies, vertically integrated with appropriate transaction cost business models and equity buffers, or they invent a way to compete against them by virtue of having had a ship redelivered. It’s just not serious.

I have said this a lot before, but it has never been truer in offshore: just because something cost a lot to build doesn’t make it valuable.

EZRA fate depends on more than debt write off… it would need significant capital

“Don’t cry because it’s over, smile because it happened.” 

– Dr Suess

An update on the EZRA situation in the Straits Times this morning deals with one part of the EZRA problem:

Much of the company’s fate now hinges on the willingness of its creditors, including bondholders, to write off – whether partially or in full – its massive debt.

Which is true as I have said many times before here, but this would be nowhere near enough. What EZRA would need in addition to a massive debt writedown is a gargantuan injection of equity to fund the company through until profitability. I don’t what the exact number would be, but it is in the tens of millions, and I suspect that number is scaring the banks now. It would also need a completely new leadership team, but I will treat that as a given.

As the article rightly points out the banks exposure is to the high-end vessels like the Lewek Constellation. An engineering marvel it may be, a liquid asset that could be sold at anything like book value, it is not. I often talk here about asset specificity, which the offshore industry and their financial providers spectacularly mispriced in the last boom, but the Lewek Constellation is also an example of a complementary asset: the return on the asset increases the marginal return to another (or its owner). In the hands of a contractor wanting to do deepwater pipelay it’s a very valuable asset, but the reverse is also true, without the right owner such a specific asset is actually close to valueless. Intuitively we know this to be right about the Lewek Constellation, there is nothing else that can be done with that vessel without enormously expensive modifications. Banks should have had a much lower loan-to-value ratio on the vessel, in effect it was a project that was entirely equity risk should it go wrong, because even to hold it at port costs ~USD 15k per day, and it will take months to sell at a fraction of its build cost (unless Subsea 7 are silly enough to buy it) as the Ceona Amazon did.

There was a straight asymmetric payoff for EZRA shareholders here where they put up a fraction of the value of such a complex asset and received all the benefits if it worked and the banks were left holding an unsellable asset with high running costs if it didn’t. It is also clear, and this should be a warning to anyone thinking of funding this, that EZRA massively underestimated how long it would take the vessel to get decent utilisation, and therefore how much capital would be required to fund the roll-out of the Lewek Constellation. A new contractor could realistically only hope to win one or two jobs a year with such a new specialised asset, the EZRA equity holders would have had to accept dramatically lower utilisation than anyone else, and therefore lower immediate payouts (dividends), for the prospect of a higher value firm in the future (if you were following MM theory). But that is equity risk and it is clearly a big number when funding a deepwater pipelay asset to challenge the world’s industry leaders.

But the banks behind EZRA have a choice: accept the loss now, or risk putting millions more in working capital into the venture in the hope that the asset values will increase enough, and the company can repay even more money in the future. Both are really bad options in the current market. Any new equity investor not already exposed to this company would demand market prices for the assets, which doesn’t help the banks at all, but to take an equity position (whatever for the semantic legal definition the capital injection took) to dig themselves out of a very deep hole is a real problem for banks. Equity risk has to be reserved at almost a 1:1 ratio under capital adequacy provisions at the moment, and for good reason: no one can tell when this market is coming back, and indeed if it will ever come back like before.

And even if the market turns a reconstituted EZRA would be competing against Technip, Subsea 7, McDermott, and maybe, longer-term, Saipem (for another blog day). This new company would require sufficient capital to convince the Board of any potential customers that they were the right partner for a large, strategically important, complex offshore field development that would cost in the tens-to-hundreds of millions of dollars. I don’t see anyone taking them up on such a remarkably unattractive offer, in this market, with a surplus of good assets and contractor capacity, you would be mad to willingly choose EZRA as your offshore development partner. All engineering and procurement work for long-term projects is effectively contractor specific and exposes potential E&P customers to becoming unsecured creditors should the new EZRA fail, so it would need a fortress-like balance sheet to convince people they will be here next year, or the year after, but would you hand over a key strategic project to a contractor who has just come out of Chap 11 and defaulted on a large number of people throughout the supply chain? I just don’t see it.

In addition, it would appear that the Norwegian arm is to be liquidated and contracting on this scale only works as a global operation. There is simply no industrial logic for a recapitalised EZRA.

If the banks want a lesson in how expensive a strategy of providing working capital in a depressed offshore market can be they need look no further than Nor Offshore and their two DSVs parked at Blyth. Having raised USD 15m last November, and making a big deal about how much financial flexibility this gave them, they now look certain to have to raise funds again at the end of this year as the entire amount will have been spent on working capital without any work being generated in 2017 (remarkably like 2016 for them).

Nor are desperately hoping that their combined bid with Oceaneering for the BP Trinidad work will come to them. I don’t see it. Bibby have the Bibby Sapphire in the Gulf, know the worksite etc. DOF have the DOF Achiever in the region as well. Would BP really bring a new DSV, with a new crew, that hasn’t dived in a year, and put it into a complex and tidal worksite? I rate their chances at less than 5% (and on a rational basis 0%). Unless Oceaneering has a remarkable relationship with someone at BP I don’t see it happening: at the end of the day a DSV puts people on the seabed and someone at BP would be accepting that if anything went wrong from a safety perspective they had taken a very risky option. And given the market BP would not save any money in doing something so risky. BP need the work done and they need it done safely.  Sure BP, try and get the price down, but who would risk their job to take such a decision? Safety first in everything we do right?

And even if Nor/Oceaneering won the work it’s a 20-25 day transit, 400k on fuel (which BP won’t pay for), and then sea trials, bell run trials etc. Madness. The Nor bondholders will be going backwards in cash flow terms given current day rates at OpEx only, just to get the boat moved. So they will be raising money at the end of the year, or selling the vessels for a lot less than they had hoped, when they raised the USD 15m last year. It is literally locked in because they have no other work and no hope of recovering their liquidity position given the market and their position in it.

Such a situation is magnified a hundred times for the banks involved in EZRA. Someone senior would have to agree to in effect provide enough working capital for at least 24 months to prove they were going to make it through, potentially offer refund guarantees against procurement and engineering etc. As Nor has shown there is no guarantee that conditions will improve in time if you simply sit back and watch. And Nor is bidding on short-cycle projects, most of the construction projects EZRA would have to tender take years to come to fruition and the tendering costs, which require vast engineering resources, are extremely expensive (particularly when you are starting with a pipeline of nothing). As I have said before as well there is no proof that EZRA was actually any good at contracting: the BHP project in Trinidad I believe was a significant loss maker, I have had many people tell me the engineering coming out of Singapore was substandard, and I spoke to someone about the work performed in the Med and they couldn’t have been more critical of the work standard. EZRA is a busted flush.

Investors, or potential investors, should remember my favourite maxim of The Great One: markets can remain irrational longer than you can remain solvent (and I am not even sure they are being irrational at the moment). People keep coming up with really complex theories about EZRA and yet I see it really simply: find me a rational investor who would pump hundreds of millions of dollars into a new subsea contracting company at the moment, in an oversupplied and fiercely competitive market, with an uncertain future, and the industry as whole operating at negative economic value? Until you can find this mythical institution there will be no EZRA. The working capital costs of offshore contracting are so high that only a fool backs a business model with no clear path to decent utilisation.

The solution here is clearly for the banks to approach another contractor with a deal that would preserve asset value while taking capacity out the market. Maybe the banks swap the assets for a stake in Ocean Installer? Let Subsea 7 take the specialist vessels for nothing and some warrants? Save face somehow through financial engineering. Because the truth is the assets really are worth collectively hundreds of millions less than book value in the new environment and no one wants to be exposed to the OpEx of them. Pumping a company with a poor industrial strategy and futile market position full of working capital is the last thing the industry needs, and frankly won’t help the organisations that do it in the long-run.