If only it wasn’t a ship…

For those who want a little clarity re: my comments on Standard Drilling yesterday it really comes down to this paragraph in their most recent financial results:

Looking at the performance of the vessels there is a positive EBITDA (adj.) excluding start-up cost, dry dock, special survey and maintenance in Q2 18 of USD 0,4 million (Q2 1.7 negative USD 1,1 million) from chartering out the 5 large –sized PSV’s. Including the ownership in PSV Opportunity AS (25.53%) and in Northern PSV AS (25.53%) the group netted a positive EBITDA (adj.) excluding start-up cost, dry dock, special survey and maintenance of USD 0,2 million (Q2 17 negative USD 1,5 million).

To put this in laymans terms: the company has calculated an adjusted cash flow and said “hey, if the costs of dry docks, survey, and maintenance were excluded from the running of these assets we would have made 0.x million”…Excluding maintenance????!…But then it wouldn’t be a ship would it?  It would be like a property which you purchased in a property crash and then held onto paying only land tax until the value recovered? But the whole point of why buying a ship in a downturn is really risky is because it has running costs so excluding those is just an offence to common sense. EBITDA is a flawed metric at the best of times, adjusted EBITDA is close to meaningless.

Also, as can be seen from PSV Opportunity I, the start-up, dry dock, survey costs etc are material so excluding them is also deliberate obsfucation:

PSV OP I Structure.png

Source: PSV Opportunity I Information Memorandum

If only they hadn’t purchased ships … but they did…

Offshore takeovers and the psychology of preferences…

Haile selassie.jpg

Courtier T.L. — Amid all the people starving, missionaries and nurses clamoring, students rioting, and police cracking heads, His Serene Majesty went to Eritrea, where he was received by his grandson, Fleet Commander Eskinder Desta, with whom he intended to make an official cruise on the flagship Ethiopia. They could only manage to start one engine, however, and the cruise had to be called off. His Highness then moved to the French ship Protet, where he was received on board by Hiele, the well-known admiral from Marseille. The next day, in the port of Massawa, His Most Ineffable Highness raised himself for the occasion to the rank of Grand Admiral of the Imperial Fleet, and made seven cadets officers, thereby increasing our naval power. Also he summoned the wretched notables from the north who had been accused by the missionaries and nurses of speculation and stealing from the starving, and he conferred high distinctions on them to prove that they were innocent and to curb the foreign gossip and slander.

Ryszard Kapuscinski, “The Emperor” (1978)

“It was surreal. When someone asked why he was doing the deal, here–now, he actually said, basically, ‘Because Americans are the dumbest investors around, and there’s lots of liquidity in this market.’”

From Kathryn Welling

 

An industry in decline has much in common with the decline of an Empire and the ancien regime. The changing of the guard, the Schumpterian competition that upsets the stability of the known order, is a constant in the evolution of social systems. Kapuscinski’s account of the fall of Haile Selassie’s empire is a classic account of a system unable to intepret information in the light of new objective realities with direct relevance to businesses facing structural changes. 

I think one needs to look at recent takeovers in offshore with a degree of cynicism that moves beyond the stated narrative of ‘confidence in the future’ based on rising oil prices, but also reflects the unwillingness of the participants to objectively view the risks being taken as the ancien regime of offshore faces a more competitive environment. One of the best comments I have read on the Tranocean/Ocean Rig deal is from Bassoe Offshore ‘Transocean Saves Ocean Rig from slow-moving train wreck‘. But the article only highlights the huge utilisation risks this deal (like so many others) creates: if the work doesn’t come at forecast levels Transocean will have gifted value to Ocean Rig who had few other options. A collection of rigs in cold-stack is not worth billions.

I would also add that I think the Transocean/Ocean Rig and Tidewater/Gulfmark takeovers bear striking similarities beyond the superficial of underutilised asset companies proffering a Common Knowledge of future confidence in future demand. The core similarity is that the shareholders of the selling entities were largely restructured debt holders and distressed debt investors seeking an exit from their investments. Behind the scenes these investors appear to have looked at the lack of forward demand, the high cash burn rate, and the willingness and ability of their competitors to burn cash with an identical strategy and asset base, and instructed an investment bank to get them out of their position. A peculiarity of the ORIG deal is the ability of the colourful Mr Economou to extract $130m over and above his proportionate economic interest in the company (the MSA break fee in the presentation), a situation that I imagine only encouraged the other shareholders to want to relinquish control (FT Alphaville has some interesting background on the him and here).

It is worth taking a recap on what the Common Knowledge was until quite recently (see here and here ) regarding the offshore industry (pushed by the Missionaries at the investment banks and other promoters). In 2017 and at the start of 2018 a credible story, as can be seen from the Seadrill restructuring presentation below, was for a sharp rebound in day rates and utilisation. The Seadrill restructuring was so complex and long that by late 2017 when it was actually due for completion, an update had to be issued and lo-and-behold the recovery was further off than first anticipated (if at all)…

Seadrill VA Dec 17.png

This presentation was by no means unique. Credible people will tell you that not only will day-rates double in three years (or less), but also that this will happen in addition to utilisation hitting 2014 levels. And this will all happen apparently in an environment where E&P companies are deliberately using shale as a competing investment to lower offshore costs…

It may happen, I don’t know the future, there is Knightian uncertainty, but on a probability weighted basis I would argue these sorts of outcomes are low probability events. The offshore industry will over time reach a new equilibrium in terms of demand and supply, in almost all other industries where there has been severe overcapacity issues before normalisation, it has led to lower structural profits on an ongoing basis.

Financial markets work on narratives and Common Knowledge as much fundamental valuation models rooted in the Efficient Market Hypothesis. Indeed these are the core of a financial bubble: a mis-alignment of current prices with long-term risk-weighted returns. What offshore industry particpants wanted to believe in 2017, against the face of significant evidence to the contrary, was that there would be a quick rebound in the demand for offshore drilling and subsea services. Despite the public pronouncements of the major E&P companies that CapEx was fixed and excess cash would be used to pay shareholders or reduce debt, despite the clear investment boom forming in shale, and despite stubbornly low day rates from their own contracting operations. People wanted to believe.

And so the investors rushed in. For Seadrill, for Borr Drilling, for Standard Drilling, for Solstad Farstad, and a myriad of others. While other investors through restructurings became reluctantly (pre-crash security holders) and willingly (post-crash distress debt investors) owners of these companies. Now, having realised that they own asset heavy companies, losing vast amounts of cash, with no possibility of bank lending to support asset values, and a slow growing market, they want out.

The meme for these deals is meant to be one of success… but really it isn’t. And just as the hard cash flow constraint is binding on the individual companies involved many of the hedge fund investors who get involved in these deals are required to produce quarterly performance reports. Charging 2/20 for an oil derived asset declining in the face of rising oil prices can cause questions, or even worse, redemptions.

So having rapidly opened the ‘black box’ of the companies they own the shareholders in both Gulfmark and ORIG realised that they were the proud owners of companies with no immediate respite from the market. The the most logical way to get out was to get shares in an even bigger entity where the shares are significantly more liquid and tradeable. That management of the acquired entities managed to get an acquisition premium is testament to the skills of the bankers involved no doubt, but also down to the fact that the acquiring companies wanted to be bigger, not because they really believe in a market recovery and pricing power (although the pricing power is valid), but because if or when they next raise capital it is better to be bigger in absolute value terms. Show me the incentive and I’ll show you the outcome…

In behavioural finance it is well known that humans overweight the possibility effect of unlikely high risk outcomes and underweight more likely certainty effects (the canonical reference is here):

POP 2018

What does this mean for offshore in general and Transocean/ORIG in particular? It means that the managers backing this deal are overweighting the possibility of a sudden and unexpected rise in offshore demand versus the more statistically likely chance of a gradual return to equilibrium of the market. It is exactly the same miscalculation that the management and shareholders of Borr Drilling appear to have made. The decline in share values recently indicates some shareholders in all these companies get the deal here. The risk of a slow recovery, and a vast increase in the stacking costs of the ORIG rigs is borne more significantly by Transocean shareholders who have borrowed ~$900m to fund the deal, while the upside is shared on a proportionate economic interest basis.

I have confidence in offshore as a production technique for the long-term. It will be a significant part of the energy mix for the foreseeable future. But a 2008 style recovery, given the importance of shale as a marginal producer and the increased offshore fleet size, looks to be an unlikely outcome that is still being heavily being bet on.

 

Scrapping and UKCS North Sea demand…

Spirit Energy (67% owned by Centrica) awarded a 3 well / 6 month drilling contract this week to the Transocean Leader. The Transocean Leader was built-in 1987, 4500ft 3G semi, that had a major upgrade in 2012. I remember 1987, my first year of high school, the All Blacks won the inaugural Rugby World Cup with ‘The Iceman (Michael Jones)’, Fleetwood Mac and U2 were cool (or I thought they were), my sister listened to Whitney Houston (okay that isn’t strictly true more The Dead Kennedys). In other words it was a while ago. I’m not a rig expert, and like vessels there are a lot of nuances around what kit can at times do what job. I don’t want to get into those, and my point here isn’t to publish a post every time an old rig wins a job.

My point is that this is a 31-year-old rig, that earlier this year had operational problems forcing it to return to a shipyard for repair before it could continue its contracted workscope, could comfortably win work with a significant UKCS (and international) operator. At 31 years old, and operating in the UK sector, it would be unreasonable to not to expect the odd issue, and indeed when that happened Dana and Transocean settled on a commercial deal to avoid contract termination. E&P operators may prefer new kit, find me an engineer who doesn’t, but the commercial guys like best priced kit in the current environment, and at the moment they are firmly in-charge of procurement.

For all the talk of scrapping being inevitable there are a lot of examples of older kit being contracted by big owners. Simply marking a build year and saying that everything older than that will be scrapped is proving to be an unrealistic forecast methodology across all asset classes (i.e. Fletcher Shipping with the Standard Drilling PSVs). Scrapping is likely to be far more selective around owner financial resources, work programmes forecast, and age, with the relationship between all three more important than any one variable.

In any other industry with cyclical demand equipment is often worked until likely maintenance costs exceed marginal profits. Fully depreciated equipment can have a major (positive) impact on the P&L for struggling companies. As industry demand rises older, less efficient, equipment is brought out to operate at a higher marginal cost. The oil industry is going the same way and while newer rigs and jack-ups may be preferred for drilling work that is clearly not the case in all situations. In plug-and-abandonment work in particular, which is less time-sensitive and more price-sensitive, there is absolutely no indication that new rigs are preferred unless their performance compensates for a cost differential (a very high bar to pass). There is also minimal-to-no evidence of newer rigs attracting anything like the sort of day rate that would allow them to cover their cost of capital versus new-build cost which is surely the first stage in a demand driven recovery?

There has been a lot of discussion lately about the new investors in the North Sea and how they are changing the economic makeup of the area, the UKCS in particular. For the supply chain one thing the new (operationally and/or financially) leveraged companies definitely bring is a relentless focus on pragmatism and cost control that simply was not as evident at larger E&P companies (who tend to excel at larger more complex developments). These might well be the right type of companies to extract the maximum resources from a mature basin, but for the supply chain the relentless focus on cost control over global and gold standards marks a significant change in procurement priorities. This is a long-term deflationary trend for the supply chain.

However, for the subsea and supply industries on the UKCS they better hope this works. The most recent stats from Oil and Gas UK show that CapEx work simply does not have the drilled inventory for a quick upturn in demand, and while the construction assets play in the maintenance market oversupply will continue. The decline in development wells, which drive tie-back activity and is leading indicator of small field developments, is what is causing huge problems for the tier-2 subsea contractors on the demand side. This isn’t going to change until drilling programmes increase in volume.

UKCS Statistics (2017)

Oil and Gas UK activity 2017.png

Source: Oil and Gas UK.

 

Financial crises comparisons…

This article from Gillian Tett on whether we have learnt the lessons from previous financial crises contains this quote:

But whatever their statistical size, crises share two things. First, the pre-crisis period is marked by hubris, greed, opacity — and a tunnel vision among financiers that makes it impossible for them to assess risks. Second, when the crisis hits, there is a sudden loss of trust, among investors, governments, institutions or all three. If you want to understand financial crises, then, it pays to remember that the roots of the word “credit” comes from the Latin “credere”, meaning “to believe”: finance does not work without faith. The irony, though, is that too much trust creates bubbles that (almost) inevitably burst.

My hypothesis is that offshore energy has suffered both from the bursting of a credit bubble (that saw for example its largest specialist lender DVB Bank go effectively bankrupt), as well as a structural change in the demand for offshore oil brought on by shale. The interrelationship between these two events is at the core of my thinking.

But the above paragraph is clearly a good summation of the 2000-2014 offshore boom. As in a banking crisis offshore asset owners had high embedded leverage on long term financing contracts funded with a series of smaller and shorter duration contracts with E&P companies. The asset owners, like banks, were committed to a long-term collection of highly illiquid assets that relied on a buoyant short-term contracting market. Like all booms there was clearly “hubris, greed, and opacity”.

When this delicate balance changed the enitre funding model of the industry was called into question and the lack of rebound on the demand side has led to severe overcapacity issues that – understandably – have left stakeholders reluctant to address. This quote also seems apt:

But shattered trust is hard to restore — particularly when governments or bankers try to sweep problems under the carpet, say with creative accounting tricks. “You can put rotten meat in the freezer to stop it smelling — but its still rotten,” one Japanese official joked to me as he watched American attempts to reassure the markets, turning to some of the same tricks the Tokyo government had once tried — and failed — to use a decade before.

Permian export capacity, marginal investment, and disintermediation…

“O human race, born to fly upward, wherefore at a little wind dost thou so fall?”
Dante Alighieri, The Divine Comedy

Big news on capital investment in Permian takeout capacity today:  Trafigura Group and Enterprise Product Partners are independently looking to build significant VLCC  export terminals in Houston. The two combined terminals would allow for 2.4m barrels of crude a day to flow out of Houston ports: given that global liquids production is ~100m barrels a day these two terminals allow for around 2.4% of global production to be reallocated through one location.

Permian pipeline capacity is growing by 2m barrels in the next two years. If you were wondering where that oil was going this is one large trading house and one infrastructure provider making their respective moves. This is just a further example of the continued capital deepening in the region that will only further enhance and encourage greater investment in shale-based production.

One cannot help but note the contrast between the Trafigura business model and that of an offshore energy company. Trafigura is providing infrastructure and distribution capability to a whole host of smaller E&P companies that will concentrate on production and require CapEx only to hook-up to a pipeline (or less commonly a rail) network. Trafigura gets (at least) an infrastructure style return on the export facility and full exposure to the commodity price and volume as a trading house (which is what they want). But what it doesn’t have to do is develop a major E&P presence in the basin : in economics/ management speak they have disintermediated the E&P supply chain. It might sound like a dot-com era buzzword but it’s real.

Trafigura has the perfect supplier base of small companies, who wish to sell 100% of output at the marginal (i.e. spot market) price, and are constantly seeking innovative ways to extract that product at the lowest possible cost. In an industry where a host of smaller companies supply rigs and crews to drill wells the expensive coordination costs of this are being farmed out to the smaller companies. Very low barriers to entry, literally $10m per well and full rig crews for only a deposit, will ensure that greater offtake capacity keeps margins capped (at the level required to induce new firms) while Trafigura controls returns that require capital and market power. It is the sort of market and business that locks in structurally higher profits for the infrastructure and distribution arm while pushing CapEx back to E&P companies and their supply chain. If oil prices slump and some of the production companies go bankrupt then their assets will simply attract new buyers at a level that reflects the marginal cost of production and they will still need export and distribution facilities.

This for offshore is where competition for marginal investment dollars resides. A core of finance theory is that returns are linked to risk. You might well be able to get a lower per barrel cost from an offshore field but you have to risk your capital for a significantly longer period of time in an era of very volatile oil prices. Not only that but most offshore developments require that you invest in subsea processing equipment and offtake capability to get to a shared pipeline or increasingly to a FPSO for larger developments. Finance theory also teaches you that all projects that are NPV positive should be funded but the institutional mechanics of raising capital, and the impact of market sentiment on sector investments, mean that isn’t always the case (although really you could just argue that the finance providers have a different view of the risk involved).

Regardless, as the graph at the top of this article shows capital expenditure to offshore projects has declined ~29%!! as a proportion of the total allocation since 2016 (from 41% to 29%) while capital to onshore conventional and shale has grown (IEA) . This is well below the 2000-2010 average and if continued is a large structural industry change. Competition for capital and marginal production is driving this change and there is real competition. There is no ‘inflection point’ for offshore demand, or ‘recovery to prepare for’, without a marked change in this trend. Offshore is losing the battle for capital at the margin and remains competitive only by supplying assets below their economic cost.

Since the downturn in 2014 the holy grail of subsea investment has been to try and find investors willing to buy and lease the infrastructure as opposed to taking E&P risk. The problems with such an idea are legion: the kit is very site and customer specific, has limited residual value, and may struggle to get seniority over the reserves below in the event of a default driven by low oil prices. It is in short very difficult to create something that isn’t simply quasi- equity in the field and surely should be priced at the same level? The ability to genuinely split exploration and production risk from distribution risk, the hallmark of the US midstream system, offers a financing and business model innovation that makes it easier to allow large sums of capital to be raised and further deepen the capital base for production in the region. Finance matters in innovation.

As I keep saying this isn’t the end of offshore but it heralds a new kind of offshore surely? Large deepwater developments allow fully integrated E&P majors to take signficant development complexity, capital, timing, and offtake risk. These companies talk of ‘advantaged oil’ and they have it in these developments. Trading houses with export capability and infrastructure have advantaged oil in their network of production companies who aim to sell 100% of output at the margin, none of whom are large enough to impact the price they pay for the product, but mid sized offshore companies strike me as under real threat and limited in size to the proportion of oil shale/tight oil can supply.

Mid-sized offshore companies do not have the portfolio advantages that large oil companies do. Every development represents a significant fraction of their investment plans and there is a limit to the technical complexity and capital required of projects they can undertake. Previously their ‘advantaged oil’ was access to a resource basin that was needed but did not move the production needle for larger companies. As riskier investments they raised capital on smaller markets (AIM, Oslo OTC, TSX) and used reserves-based financing and bonds along with farmout agreements. But this took time and the higher leverage levels make this risky. The cost of equity, when available, is much higher than in the past because the expectation is that the price of oil will be more volatile. And now the returns are capped by the marginal cost and volumes at which shale companies can supply, which is a new and significant risk factor, particularly in an investment with a multi-year gestation period.

Yet these small-mid sized offshore E&P companies represented the demand at the margin for offshore assets. Large complex drilling campaigns and projects for tier 1 E&P companies always attracted good bids and a relatively efficient price from contractors, but smaller regional projects did not. The margins were higher and the risks greater. On the IRM side these companies negotiated harder on the price but they still had a volume of work that needed to be undertaken. It is these companies, their inability to get finance because of their complete lack of advantaged oil, that are also ensuring now that CapEx (and therefore demand) is not recovering as in previous cycles. These E&P companies are price taking firms with signficant operational leverage/fixed commitments and limited financial or operational flexibility in the short-term. Currently they rely on developments being profitable via the supply chain providing assets below their economic cost. That is not a great strategic position to be in. When there was no competition for your product the story was completely different, but the shale revolution is real.

This chart shows you that demand growth for crude slowed 1% year-on-year for two months and the market became oversupplied (hence the drop in the price of oil recently):

IMG_0731.JPG

Investors in oil closely watch volatility indicators like this and as I have said before the logical investment strategy is to invest more secure lower margin companies.

The three major risks to supply listed hy Woodmac at the moment are Venezuela, Libya, and Iran. These are geopolitical risks that could easily end in the short-run. Iran is self-induced and the situation in Venzuela so unsustainable (the real question isn’t why someone tried to assasinate Maduro but why everyone else isn’t?) that it surely cannot last? In prior eras the solution was to build long lasting production capacity in politically stable places. Now surely the solution is to use temporary production capacity where possible and let the price signal take some of the strain?

I think it is axiomatic that offshore cannot boom without a recovery in offshore CapEx spending. At the margin offshore has ceded significant market share in this competition to shale. Major structural change will be needed in the industry before the situation reverses based on current trends.

Weekend shale read… The Red Queen for offshore…

“Well, in our country,” said Alice, still panting a little, “you’d generally get to somewhere else—if you run very fast for a long time, as we’ve been doing.”

“A slow sort of country!” said the Queen. “Now, here, you see, it takes all the running you can do, to keep in the same place. If you want to get somewhere else, you must run at least twice as fast as that!”

Alice in Wonderland, Lewis Carrol

Applied to a business context, the Red Queen can be seen as a contest in which each firm’s performance depends on the firm’s matching or exceeding the actions of rivals. In these contests, performance increases gained by one firm as a result of innovative actions tend to lead to a performance decrease in other firms. The only way rival firms in such competitive races can maintain their performance relative to others is by taking actions of their own. Each firm is forced by the others in an industry to participate in continuous and escalating actions and development that are such that all the firms end up racing as fast as they can just to stand still relative to competitors.

THE RED QUEEN EFFECT: COMPETITIVE ACTIONS AND FIRM PERFORMANCE

Derfus et al., 2008

 

Stressing output is the key to improving productivity, while looking to increase activity can result in just the opposite.

Paul Gauguin

 

The IEA has done a review of shale companies financing and for those hoping that they represent some sort of ephemeral phenomenon that will pass as soon as the junk bond market closes, well rates decline, or some other exogenous event arises, they are likely to be disappointed. It’s a short read and well worth the effort. I called shale an industrial revolution the other day and the IEA post is a good short precis on how this came about in financial stages.

SPE also has had some good articles recently on the constant productivity the shale industry is using to drive down costs. This one on Equinor for example:

One of the drawbacks of the status quo is that it requires small armies of field personnel to interpret SCADA data and then adjust set-points to get pumping units back into optimal operating ranges. This manual process can consume half-an-hour per well to complete; downtime that quickly adds up in a field of hundreds.

“What we are talking about is having the machine do that entire workflow,” Chris Robart, Ambyint’s president of US operations said…

The Bakken project comes after a pilot that included 50 of Equinor’s wells, which saw a net production increase of 6%—considerably larger uplift figures were seen from those wells suffering from under-pumping.

Or this one dealing with Parent/ Child wells, which a few months ago seemed to be the latest reason to explain why shale wasn’t a sustainable form of energy, but the industry has solved part of this problem through “cube development”:

But the prize for coining the term cube development goes to Encana Corporation, which says the strategy has increased early well productivity in one of its Permian fields by 70% over the past 2 years. Despite the term’s growing popularity within engineering circles, some companies continue to use different terms such as QEP’s “tank-style completions” for what is seen as the same general practice.

I don’t understand the technology but I have faith that day-in day-out new techniques are being developed that will drive down the costs of extraction and production in the shale industry. You need to be a technical pessimist, which in this age is hard, to believe this productivity direction cannot continue (see Citi here).

Over time the offshore industry will change to compete with shale. The economic force of competition will ensure this. But in order to compete it will need to reduce the cost and time of being offshore dramatically and focuson on high-flow low lift cost projects. Something well underway in the Gulf of Mexico at the moment.

There are huge moves in offshore to improve productivity: all righty focused on spending lowering cost and reducing time to first oil. Some, but by no means all, contractors focused on engineering are starting to see improved profitability. But the sunk investments made in offshore vessels, jack-ups, and rigs have largely had their equity wiped out in the last few years and this is enabling the offshore industry to compete on price and risk in terms of capital allocation from E&P companies. For as long as that is it’s only, or major, competitive advantage all that beckons is an industry that slowly runs down its capital base until project cost inflation can rise. Something that becomes ever more distant the more competitive shale becomes. I realise it’s a bleak prognosis but there isn’t much else on offer.

What is an offshore construction vessel worth?

There is an article from Subsea World News here that is sure to have bank risk officers and CFOs choking over their coffee… VesselValues new OCV is launching a new analytics tool for the sector. The ten most valuable vessels in the OCV sector are apparently:

  • Normand Maximus $189m;
  • Fortitude $99 million;
  • Deep Explorer $97 million;
  • Siem Helix 2 $96 million;
  • Seven Kestrel $95 million;
  • Siem Helix 1 $95 million;
  • Island Venture $94 million;
  • Viking Neptun $92 million;
  • Far Sentinel $90 million;
  • Far Sleipner $89 million;

Firstly, look at the depreciation this would imply? As an example the Maximus was delivered in 2016 at a contract price of USD $367m. So in less than 2 years the vessel has dropped about 48% in value. Similarly the two new DSVs the Seven Kestrel and Deep Explorer appear to be worth about 67% of value for a little over two years depreciation.

Secondly, the methodology. I broadly agree with using an economic fundamentals approach to valuation. And I definitely agree that in a future of lower SURF project margins that these assets have a lower price than would have been implied when the vessels were ordered. I have doubts that you can seperate out completely the value of a reel-lay ship like Maximus from the value of the projects it works on but you need to start somewhere. It is clear that SURF projects will have a lower structural margin going forward and logically this must be reflected in a vessel’s value so I agree with the overall idea of what is being said.

There is a spot market for DSVs on the other hand so their value must reflect this as well as the SURF projects market where larger contractors traditionally cross-subsidised their investment in these assets. A 33% reduction in value in two years might well reflect an ongoing structural change in the North Sea DSV market and is consistent with the Nor/Boskalis transactions on an ongoing basis. This adds weight to the fact York have overpaid significantly for Bibby, who would be unable to add any future capacity to the DSV market in the pricing model this would imply and not even be earning enough to justify a replacement asset. Given the Polaris will need a fourth special survey next year, and is operating at below economic value at current market rates, even justifying the cost of the drydock in cash terms on a rational basis is difficult.

Depreciation levels like this imply clearly that the industry needs less capital in it and a supply side reduction to adjust to normal levels. Technip and Subsea 7 are big enough to trade through this and will realise the reality of similar figures internally even if they don’t take a writedown to reflect this. Boskalis looks to have purchased at fair value not bargain value to enter the North Sea DSV market. SolstadFarstad on the hand have major financial issues and Saipem locked into a charter rate for the next 8 years at way above market rates, but with earnings dependent on the current market, will have to admit that while the Maximus might be a project enabler it will also be a significant drag on operational earnings. The VesselsValue number seems to be a fair reflection of what that overall number might look like.

The longer the “offshore recovery” remains illusory the harder it will be for banks, CFOs, and auditors to ignore the reality of some sort of rational, economic value criteria, for offshore assets based on the cash flows the assets can actually generate.