Random weekend energy thoughts… Productivity, costs, and DSV asset values…

Permian shale and tight production in the third quarter was 338,000 barrels per day, representing an increase of 150,000 barrels per day. Let me say it again: this is up 80% relative to the same quarter last year. As many of you will realize, that’s the equivalent of adding a midsized Permian pure play E&P company in a matter of months.

Pat Yarrington, CFO, Chevron, on the Q3 2018 results call

John Howe from UT2 posted the photo above on Friday and kindly allowed me to reproduce the it. The Seawell cost £35m in 1987 and according to the Bank of England Inflation Calculator the same vessel would cost ~£94m in 2018 in real terms. In 1987 the USD/UK exchange rate was ~1.5 so the Seawell cost $53m and inflation adjusted around $132m (at current exchange rates).

Compare that with the most recent numbers we have for a new Dive Support Vessel (“DSV”) of a similar spec: the Vard 801 ex Haldane that was contracted at $165m (sold for $105m).  That price is roughly 25% above the cost of the Seawell in real terms. You get a better crane and lower fuel consumption but in productive terms you can still only dive to 300m (and no riser tower) and I doubt the crane and the lower fuel consumption are worth paying 25% more in capital terms.

These prices don’t reflect how much the MV Seawell pushed the technological boundary when she was built when and recognised as one of the most sophisticated vessels in the world. The major £60m/$75m upgrade she received in 2014 highlights again the myth that old tonnage will naturally be scrapped as an iron cast law is wrong, but more importantly highlights the technical specification of the vessel has always been above even a high-end construction class DSV (clearly visible in the photo the riser tower must have been seen a major technological innovation in 1987) and yet it is more economic to upgrade than build new for a core North Sea well intervention and dive asset. Helix has invested in an asset that brings the benefits of low-cost from a different cost era to a new more uncertain environment.

The reasons for price inflation in OSVs are well-known and I have discussed this before (here): offshore vessels are custom designed and have a high labour content which is not subject to the same produtivity improvements and lower overall cost reduction that manufactured goods have (Baumol Cost Disease). The DP system and engine might have come down in real terms, but the dive systems certainly haven’t. Even getting hulls built in Eastern Europe and finished in Norway has not reduced the cost of new OSVs in real terms (you only have to look at Vard’s financial numbers to see the answer isn’t in shipbuilding being a structurally more profitable industry).

That sort of structural cost inflation, a hallmark of the great offshore boom of 2003-2014, was fine when there was no substitute product for offshore oil. Very few OSVs were built in a series (apart from some PSV and AHTS). But the majority of the vessels were one-off or customised designs with enormous amounts of time from ship designers, naval architects, class auditors (i.e. labour) before you even got to the fit-out stage. Structural inflation became built into the industry with day-rates in charters etc expected to go up even as assets aged and depreciated in real economic terms because demand was outpacing the ability of yards to supply the tonnage as needed.

The same cost explosion happened in pipelay but did allow buyers to access deeper water projects. Between 2003-2014 an enormous number of deepwater rigid-reel pipelay vessels were built (in a relative sense) with each new vessel having even more top tension etc. than the last; but the parameters were essentially the same: they were just seeking to push the boundary of the same engineering constraints. The result was (again) a vast increase in real costs but one that was partially offset by advances in new pipe and riser technology that allowed uneconomic fields to be developed. Now Airborne and Magma are working on solutions that could make many of these assets redundant. Only time will tell if those offshore companies who have made vast investments in pipelay vessels will have to sell them at marginal cost to compete with composite pipe if the solution gets large-scale operator acceptance (i.e. Petrobras). However, if composite pipe and risers get accepted by E&P companies on a commercial scale those deepwater lay assets are worth substantially less than book value would imply (I actually think the most likely scenario is a gradual erosion of the fleet as it is not replaced).

But now there is a competitor to offshore production: shale. And it is clearly taking investment at the margin from offshore oil and gas. And shale production is an industry subject to vast economies of scale and productivity improvements. The latest Chevron results make clear that they have built a vast, and economically viable, shale business that added 150k barrels per day of production at an 80% growth rate year-on-year:

Chevron Q3 2018 Permian .png

To put that in perspective when Siccar Point gets the Cambo field up and going they will be at 15k per day and it will have taken them years (and the point is they are a quality firm with Blackstone/Bluewater as investors ensuring the do not face a financing constraint).

What makes shale economic is the vast economies of scale and scope available to companies like Chevron. E&P companies producing shale are adding vast amounts of production volume every year and theories that they are not making money doing this are starting to sound like Moon photo hoax stories. E&P companies throw money and technology at a known geological formation and it delivers oil. The more money they invest the lower the unit costs become and the greater the economics of learning and innovation they can apply at even greater scale.

Offshore has a place but it needs to match the productivity benefits offered by shale because it is at a disadvantage in terms of capital flexibility and time to payback.The cost reductions in offshore that have been driven by excess capacity and an investment boom hangover, these are not sustainable and replicable advantages. In offshore everything, from the rig to well design and subsea production system, has traditionally been custom designed (or had a significant amount of rework per development). When people talk of “advantaged” offshore oil now it generally means either a) a field close to existing infrastructure, or, b) a find so big it is worth the enormous development cost. Either of those factors allow a productivity benefit that allows these fields to compete with onshore investment. But to pretend all known or unknown offshore reserves are equal in this regard is ignoring the evidence that offshore will be a far more selective investment for E&P companies and capital markets.

One of the reasons I don’t take seriously graphs like this:


…and their accompanying “supply shortage” scare stories is that the market and price mechanism have a remarkably good track record at delivering supply at an economically viable price (since like the dawn of capitalism in Mesopotamia). Modelling the sort of productivity and output benefits that E&P majors are coming up with at the moment is an issue fraught with risk because 1 or 2% compounded over a long period of time is a very large number.

As an immediate contra you get this today for example:

(Reuters) – The oil market’s two-year bull run is running into one of its biggest tests in months, facing a tidal wave of supply and growing worries about economic weakness sapping demand worldwide.

Which brings us back to DSVs in the North Sea, their asset values, and the question of whether you would commission a new one at current prices?

Last week the OGA published an excellent report on wells in the UK and its grim for the future of UK subsea, but especially for the core brownfield and greenfield projects in shallow water that DSVs specialised in. And without a CapEx boom there won’t be a utilisation boom:

OGA wells summary 2-18.png

Future drilling is expected to pick-up  mildly, although it is unfunded, but look at this:

EA well spud.png

Development Drilling.png

So the only area in the UKCS that isn’t in long-term decline is West-of Shetland which is not a DSV area. CNS and SNS were the great DSV development and maintenance areas and the decline in activity in those areas are a structural phenomena that looks unlikely to change. Any pickup is rig work is years away from translating into a Capex boom that would change the profitability of the UKCS DSV and small project fleet.

DSV driven projects have become economic in the North Sea because they are being sold well below their economic cost. Such a situation is unsustainable in the long run (particularly as the offshore assets have a very high running cost). The UKCS isn’t getting a productivity boom like shale to cover the increased costs of specialist assets like DSVs and rigs: E&P companies are merely taking advantage of a supply overhang from an investment boom. That is no sustainable for either party.

So while the period 2003-2014 was “The Great Offshore Boom” the period 2015-2025 is likely to be “The Great Rebalancing” where supply and demand both contract to meet at an equilibrium point. Supply will have to contract because at the moment it is helping to make projects economic by selling DSVs below their true economic worth, and the number of projects will have to contract eventually because that situation won’t last. E&P companies will need to pay higher rates and that will simply make less projects viable. You can clearly see from the historic drilling data that a project boom in shallow water must be a long time coming given the lags between drilling and final investment decisions.

The weak link here in the North Sea DSV market is clearly Bibby Offshore (surely soon to be branded as Rever Offshore?). As the most marginal player it is the most at risk as marginal demand shrinks. Bibby, like other DSV operators on the UKCS, serves an E&P community that is facing declining productivity relative to shale (and therefore a higher cost of capital), in a declining basin, where the cost of their DSVs is not reducing proportionately or offering increased productivity terms to cover this gap. Both Technip and Boskalis were able to buy assets at below economic cost to reduce this structural gap but the York led recapitalisation of Bibby still seems to significantly over value the Polaris and the Sapphire – particularly given implied DSV values with the Technip purchase of the Vard 801 (TBN: Deep Discovery).

DSVs made the UKCS viable and built the core infrastructure, but they did it in a rising price environment where the market was based on a fear of a lack of supply. One reason no new North Sea class DSVs were built between 1999 the Bibby Sapphire conversion in 2005 is because the price of oil declined in real terms but the price of a DSV increased meaningfully in real terms. A new generation of West of Shetland projects may keep the North Sea alive for a while longer but this work will be ROV led. A number of brownfield developments and maintenance work may keep certain “advantaged” fields going for years that will require a declining number of DSVs.

North Sea class DSV sales prices for DSVs are adjusting to their actual economic value it would appear not just reflecting a short-term market aberration.

#structural_change #this_time_it_is_different #supplymustequaldemand

Long-term North Sea subsea demand…

One of the reasons I don’t believe smaller contractors can survive in the North Sea is the change in rig demand. You can argue, although I wouldn’t, that there is going to be a boom in rig demand that might happen quickly. But for subsea to grow there has to be a CapEx boom, and unless someone can explain to me how that happens without a surge in rigs working then clearly that isn’t happening anytime soon. Funding will run out for marginal contractors long before the rigs generate enough work at this rate given the lag time between rig and subsea projects.

I made the above graph from the Baker Hugher Rig Count. The data is stark and shows that based on current rig levels the UK subsea industry must face a large contraction in construction and tie-in work in the upcoming months. The UK rig count peaked in Jan 2013 at 22 working rigs, that has dropped to 7 in Sep 18. In Norway, as can be seen from the dark blue area, the rig count peaked in Dec 12 at 25, reached that again in Sep 13, and apart from an aberration of 9 in Oct 16 has never really dropped below the upper teens, although there are currently 13 working.

The UK sector has seen peak-to-trough declines far in excess of Norwegian levels where demand has been more constant. There are a host of reasons for this including tax and industrial policy that I don’t want to get into: but the net result is clear that in Norway offshore activity is far less volatile in demand terms. Exposure as a pure UK subsea business means accepting a large decrease in the size of the opportunity.

As a follow-up to my thoughts yesterday clearly this puts Bibby under pressure. Bibby’s core competency of diving is useless in Norway (as the company has no NORSOK compliant dive vessel) and it has been unable to crack the ROV led market against DeepOcean, Reach and Ocean Installer, all of whom have strong Equinor connections and have made substantial local investments. In the UKCS a large amount of the recent rig work has been concentrated on West-of-Shetland work where there is little, if any, diving involved in the projects.

Boskalis recently won the contract for the Tyra redevelopment subsea (including diving) scope. Bibby did the original work on Tyra and it was surely a high profile priority for them to win? IRM diving has never been that profitable but the project work was. Bibby may have a large hedge fund as a shareholder (and debt owner) but that doesn’t help them. Putting that you have your shareholders’ support on the accounts only highlights it is needed to be regarded as a going concern by your auditors (necessary if you aren’t going to write the debt off). As Vard found to their dismay having a large hedge fund back a diving venture is no guarantee of getting paid when they decide to exit the industry. Customers signing large value orders over a multi-year period with Bibby may rightly be nervous that the company has the financial strength to finish their contract. Work-in-progress is merely an unsecured creditor in insolvency event.

It’s not good for Ocean Installer either. Whereas Bibby is a specialist in one area of the market OI is a generalist contractor that relied on a booming market. It has no rigid-pipelay spread or differentiating competitive advantage. Anyone can hire a vessel with a big crane and some shore based engineers and provide exactly what they do. Because of this they are a price taker in a competitive market, and the price at the moment is low. Providing day-rate engineers in China is a fully low-rent activity. Equinor has Reach and DeepOcean and whether they want to support OI as a charity project remains to be seen.

My thesis isn’t complicated (or original): when the market boomed it drew in new entrants as demand expanded rapidly and money flowed through the industry. But now the demand isn’t there and given the scale of the pullback it is the marginal contractors, the ones who entered the industry because of the booming conditions, who will be the first to go. The market adjustment from the supply side of subsea has a lot of adjustment to go before it catches up with the amount of project work that can be generated based on current rig working levels.

It’s grim up North… And the labour theory of value…

It’s Grim Up North.  The Justified Ancients of Mu Mu

Ricardo, Marx, and Mill believed that prices were determined by how much people had, in the past, invested. And that blinded them to any understanding of the workings of the market.

Friedrich Hayek

[I am not really a Hayek fan (in case anyone is interested). But he was a very smart guy who understood social and economic change processes better than most. Beyond that you get diminishing returns. As an aside I have been too busy to blog much lately, which is a shame as some really interesting things have been happening, but it doesn’t seem to have affected my visitor numbers much, which just goes to show maybe my silence is more valuable.]

The Oil and Gas UK 2018 Economic Report is out. For the North Sea supply chain there is no good news. There is clearly a limited offshore industry recovery underway as we head towards the end of summer. However, the market is plagued by overcapacity, and while service firms without offshore assets are starting to see some positive gains, if you are long on floating assets chances are you still have a  problem, it is only the severity that varies.

The UKCS is what a declining basin looks like: fewer wells of all types being drilled and dramatically lower capital expenditure. There is no silver lining here: an asset base built to deliver 2013/14 activity levels simply has too many assets for the vastly reduced flow of funds going through the supply chain. The report makes clear that the base of installed infrastructure will decline and there will be a relentless focus on cost optimisation to achieve this.

UK Capital Investment 2018.png

The volume of work may be increasing marginally but the overall value may even down on 2017 at the lower end of the 2018 forecast (purple box). Clearly £10bn being removed from the oil and gas supply chain, c. 60% down on 2014, is a structural change.

And the OpEx numbers unsurprisingly show a similar trend:

UKCS OpEx 2018.png

Party like it’s 2012 says Oil and Gas UK. Unfortunately a lot more boats and rigs were built since then.

Unit Operating Costs 2018.png

An unsurprisingly the pressure on per barrel costs seems to have reached the limits of downward pressure.

This should make supply chain managers seriously consider what their investment plans are for assets specific to the region and the likelihood of assets having to work internationally to be economic. It should also make people reassess what stuff is actually worth in a market that has reduced in size by that quantum and from which there is no realistic path to 2014 activity levels.

Technip paid $105m for the Vard 801, about $55m/45% discount to the build cost. Such a deal seems realistic to me. Some of the deals I have seen in offshore remind me of The Labour Theory of Value: if you dig a massive hole that costs a lot it must therefore be worth a lot. In reality with so much less cash floating around for assets that will service the UKCS an asset is worth the cash it can generate over its life, and the fact that it is substantially less than its replacement cost is just another clear example of how the industry will reduce its invested capital  as production levels in the basin decline. Like airlines offshore assets have a high marginal cost to operate and disposable inventory which is why you can lose so much money on them.

Boskalis appears to have paid an average of c. $60m for the two Nor vessels which equates to a similar discount on an age weighted basis. Quite where this leaves Bibby needing to replace the 20 year old Polaris and 14 year old Sapphire is anyone’s guess. But it is not a comfortable position to be in as the clear number four by size (in terms of resource access) to have competitors funding their newest assets on this basis. Yes, the shareholders may have paid an equivalent discount given the company value they brought in at, but if you want to sell the business eventually then you need a realistic economic plan that the asset base can self-fund itself, and at these sort of prices that is a long way off. Without an increase in the volume and value of construction work 4 DSV companies looks to be too many and this will be true for multiple asset classes.

As a mild comparison I came across this article on $Bloomberg regarding Permian basin mid-stream investment:

Operations in the Permian that gather oil and gas, and process fuel into propane and other liquids, have drawn almost $14 billion in investment since the start of 2017, with $9.2 billion of that coming from private companies..

That is just one part of the value chain. I get you it’s not a great comparison, but the idea is simply the ability to raise capital and deploy it in oil production, and it is clear that for Permian projects that is relatively easy at the moment. The sheer scale of the opportunities in the US at the moment is ensuring it gets attention and resources that belie a strictly “rational” basis of evaluation.


That is what a growth basin looks like. The narrative is all positive. Once short-term infrastructure challenges are resolved that stock of drilled but uncompleted will be turned into production wells.

Oil and Gas UK go to great pains to explain the economic potential of the UKCS. But finance isn’t strictly rational and I still feel they need to be realistic about the cycle time tradeoff offshore entails. Shale, as we have seen, has an enormously flexible cost base relative to offshore and that has value.

The comments I make below are part of a bigger piece that I keep wanting to write but a) don’t have the time; and, b) probably doesn’t work for a blog format. But I think the impact of the private equity companies taking over North Sea assets needs to be realistically assessed.

Don’t get me wrong here I am a massive supporter of them. In terms of the volume of cash, and the ability to buy and invest at the bottom of the cycle, the North Sea would clearly have been worse off without private equity. But the results are in and there has not been a development boom… there has been a focus on the best economic assets that may make the fields last longer, but that is a different test. There may clearly have been an investment boom relative to what there would have been without private equity money, but again that is a slightly different point.

Private equity firms have a much higher cost of capital than traditional E&P companies and at the margin that will limit the number of projects they fund. The focus on lowering costs and returning cash as quickly as possible, often to compensate for how hard it will be for the owners to exit such sizeable positions, also adds to the change in the investment and spend dynamic (on the downside obviously). I am genuinely interested to see how these large multi-billion dollar investments are exited given how much trouble the super-majors are having at getting out.

Private equity may well be the future of the North Sea but that has huge implications for the supply chain. It is also worthwhile pointing out that while the smaller companies maybe able to sweat old assets they have a limit for larger projects. Quad 204 is a classic project where it is hard to see even one of the largest PE backed companies having the technical skills and risk appetite to take on such a vast project.

The majority of the larger deals also involved significant vendor financing from the sellers. Shell had to lend Chrysaor $400m of the $3bn initial consideration. This happened not through generosity, or a desire to maintain economic exposure to the assets, but because debt finance from the capital markets or banks was simply unavailable even to such large and sophisticated buyers. Siccar Point went to the Norwegian high-yield market in January borrowing $100m at 9% for five years. The fact is finance is scarce, and when available expensive, and this is impacting the ability of E&P projects to get financed. Enquest has had to do a deeply discounted rights issue, and borrow off BP, to complete Sullam Voe.

The E&P majors are helping to finance their own exit because it is the only way they can get out. The turnaround from that to an investment boom that could raise asset values in the supply chain is a long one.

In order to make money in this environment the E&P companies, particularly those backed by private equity, are focusing on driving down costs and limiting Capex with a ruthless efficiency and commitment few in the supply chain believed possible long-term. Where offshore assets are concerned the oversupply situation only assists with this. I met one of the private equity investors last week and I can assure you there is no pressure to replace old assets, safety first definitely, economics and finance second just as definitely.

The reality for the supply chain is this is a market where it will be very hard to make money for a very long time, and in reality the glory days of 2012-2014 look extremely unlikely to return. The Oil and Gas UK report gives some important data in explaining why.

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.


Productivity and capital reduction in offshore …

“Bank executives, believers in sound money to a man when other sectors of the economy were in trouble, became less keen on monetary purity when it came to their own survival…”

Philip Coggan, Paper Promises

From the $FT on Monday:

This has helped boost UK oil and gas output from 1.42m barrels of oil equivalent per day in 2014 to 1.63m boepd in 2017, a 14.8 per cent increase…
But the industry has now managed to lower costs from an average of £19.40 a barrel in 2014 to an estimated £11.80 a barrel this year, according to the UK Oil and Gas Authority, while total expenditure on investment and exploration has fallen from £15bn to £5bn over the same period.

Let’s be clear about what this sort E&P company productivity means in terms of market and price deflation for the offshore supply chain over a four year period: OpEx -39% and CapEx down 66%%! £10bn has been taken from a market of £15bn in revenue terms for the supply chain supporting “investment and exploration”! It is an extraordinary number for an industry supported by a large amount of leverage in the supply chain and represents a fundamental structural shift.

Yes the CapEx number is variable by year, and Clair Ridge and other fields had massive expenditure last year, but this is the future of offshore in the UKCS. The gross figure is probably a good proportionate proxy for all those in market, with the most oversupplied segments perhaps taking a bigger hit, but if you are a UK focused business this is the scale of the reduction in the market. And this in an environment when the oil price rose 44%! As anyone close to the E&P companies will tell you cost pressure is still relentless. A near 13% decline in the price of Brent over the last few weeks only adding to CFO determination to keep OpEx in check.

If you take Bob Dudley’s assertion that you get 40% more volume for your value offshore the market is at £7bn in 2010 terms i.e. more than a 50% decline and a smaller installed base in the future to maintain. The sanctioning of Tolmount yesterday was good news but it doesn’t change the macro statistics: this is a rapidly shrinking basin in market expenditure terms. There is simply no linear relationship between the oil price and the demand for offshore services in  the North Sea now.

There is a reason the Vard 801 has not been taken out by Technip or Subsea 7 and that is clearly in this environment the UKCS is a very difficult place to make money.  It is not sensible to invest in fixed assets for a market facing such steep declines in size. For UK focused contractors there is simply no way to remove that volume of revenue from the market and under any realistic assumptions and expect the same number of firms to survive or profitability levels to return to past averages. The industry must contract to reflect this but the high perceived asset values of the vessels and rigs have slowed this contraction.

If you took on debt in the good times your market has shrunk rapidly but your creditors expect to be paid back from a market that was in percentage terms vastly bigger. If you don’t think offshore has any hot air left to come out then take a look at the accounts of Nordic American Offshore: a North Sea PSV ‘pure play’.

NAO in 2017 (or materially in any other year) decided not to impair the value of their PSVs because they think they will earn their value back. NAO has 10 PSVs, debt of $~140m, ~$12 in cash, and having largely spent the $47.5m raised in 2017. In 2017 it spent ~$22.5m in costs to get ~$18m in revenue and it made another loss (obviously) for H2 2018, resorting to sending non laid-up PSVs to Africa to work. There is no realistic future for this company as a standalone enterprise and no industrial logic for this company to exist at current market demand levels. The vessels are worth less than the bank debt and their market is in a steep contraction. These PSVs are on the books at over £30m each!!! Sooner or later the facts of this market contraction with their cash position will collide.

There is simply no place for these supply companies with 10-20 vessels. Sooner or later the banks will have to forclose here and simply get what they can for the vessels or they will have to write off some of their claims to encourage yet another round of investment in a loss making company whose assets are held at book value at significantly more than could be realised in a sale process. NAO fleet Value.png

That last comment above is based on using a 10 year average of PSV rates and utilisation levels. At some point the reality of needing new cash to pour into operating losses is going to collide with their “beliefs” as NAO don’t have enough cash to last until (if?) rates return to 10 year historic averages. It is very hard to see the upside for any potential investor here even if the banks wrote off 100% of their claims, something they are clearly unlikely to do.

Not that there is room at the survivors table for all the medium-sized companies either. Bankers for Maersk Supply Service have also been taking soundings for a buyer. They are seeking top dollar for a company unfortunate enough to order the Starfish class of vessels just before the market peaked, but even more unfortunate enough to have a parent able to honour the group guarantees to pay for the vessels on delivery. In 2017 they stopped posting financial results on the website but are well understood to be losing significant amounts of cash at an operating profit level.

Maersk Group are listing Maersk Drilling as they have been unable to find a buyer, but they were able to organise banks willing to back the company with debt facilities. It is very hard to see a similar situation arising with Maersk Supply where no realistic path to profitability can be plotted and creditors would remain exposed to large operating losses.

Maersk Supply has also been trying to build a contracting business when the market for projects in the UKCS has reduced by 66%. They have no competitive advantage and nothing to offer an oversupplied market. All that will happen here is they will burn OpEx trying to do this and eventually, when all the other options have failed, they will do the right thing and shut the contracting business down. While all the tier 1 (and 2) contractors have significant excess capacity there is no room in the market for a new tier 2 contractor whose sole purpose is to cross-subsidize utilisation from their vessel fleet. A JV with Maersk Drilling to work on decommissioning is unlikely to yeild anything of scale that someone with outside capital would find value in paying for.

Maersk Supply is at the upper end of the adjustment band of companies that are unlikely to survive without some sort of dramatic and unforecast change in market circumstances. Protected in better times by a massive corporate parent, and with a similar proptionate cost base, it is now exposed as a massive cash drag as its owner tries to protect its investment grade credit rating. MSS offers insignificant scale in the market, ongoing cash losses, and a very high cost base reminiscent of better times in a geographic location where this is hard to change. Maersk Supply simply isn’t a viable standalone business at the moment without a massive equity injection.

AP Moller-Maersk have vowed to do whatever it takes to protect their investment grade credit rating, at some point the material losses being generated in MSS will force their hand here. As more disparate parts of APMM are divested the trading performance of MSS will become something that will need to be cauterised.

The future of offshore supply can be seen in Asia where small nimble  companies with very low costs make money on wafer thin margins. Traders. Vessels are worked to death and meet minimum local standards but nothing more. If Standard Drilling/ Fletcher can bring ex-DP I vessels to the North Sea to compete against NAO then welcome to the future of the North Sea supply market because that is how you drive OpEx down 40%.

NAO and Maersk Supply, like a lot of other companies in the industry, found investors over the last couple of years (one external and one internal) who believed that the market would return to previous levels and it was worth funding the interim period. At each round of fundraising this becomes an ever more unlikely outcome and the costs of this rise. Slowly but surely some companies will be unable to convince potential investors that they will be the one who makes it through to the (mythical?) recovery. This slow grinding down of capacity and capital is how the industry looks set to rebalance.