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.

Demand at the margin…

“We’ve indicated we’re going to keep capital spending flat. We’re in a higher price environment, [but] we haven’t changed our capital budget, and I don’t expect that we will,” Mr Wirth said. “We will not fund every project. We will have projects that meet our economic hurdles, but we’ll choose not to fund, because we’ll have better options.”…

“Frontier-type projects, the riskier investments, are now . . . not as necessary,” he said. “And I think that has implications for everyone.”

For Chevron, that meant every project it invested in would have to be “best in class”, he said. “It can’t just be the kind of project you might have funded historically, because we’ve got better options.” [Emphasis added].

Mike Wirth, CEO, Chevron, Financial Times, July 18, 2018

Image above from Chevron.

Those statements are in essence why the next upswing in offshore will be fundamentally different to the cyclical nature of the industry between 1999 to 2014: in those periods, devoid of shale in a meaningful sense, every offshore project was approved, and the industry built an asset-delivery base accordingly.  As an example Exxon Mobil used to take it’s PSVs and AHTS up to the Arctic in March and wait for the ice to melt so they could start work immediately. That work simply doesn’t exist now. There were a large number of frontier and marginal projects deemed economic that are unlikely to ever be seen that way again (on a risk-weighted basis not just cost per recoverable barrel).

I am a big believer in offshore energy nand believe it will be a significant part of the value chain for a long while to come. The industry is clearly improving from a demand perspective, and if you are a manufacturing or engineering business (for example) then next year will be better than this year. But it isn’t the same for those long on rigs and boats because of the oversupply situation and the fact that the high fixed cost structure makes it hard to reduce costs (i.e. the asset opex is a lot higher than SG&A overhead) in a meaningful sense. The asset based industries face years of structurally lower profitability.

The reason I don’t believe there will be a comeback in offshore demand in terms of the timing and day-rate increases seen in previous cycles is because a significant number of E&P  companies are following the same strategy as Chevron. It is taken as a given in offshore that oil prices and will always come back up, and maybe they will (although the relationship between oil prices and offshore demand has changed), but the optionality of shale has a real value as well for E&P companies and they have fundamentally changed the project approval process. The industry cannot boom on maintenance and decommissioning work, the offshore fleet is so big now it requires a CapEx boom in order to have a cyclical upswing, and there are no signs of that appearing. Project approvals are up but nothing like the levels of of 2013/2014 and it is CapEx projects that will create demand at the margin to meaningfully lift day rates and utilisation levels.

E&P shareholders didn’t see that much of the last boom where high prices were given to the supply chain to expand capacity and you get the feeling they aren’t making the same mistake twice. The offshore supply chain needs to digest the implications that while ‘lower for longer‘ may not have held for oil prices it appears to be an apt description of demand for offshore services.

“Preparing for the recovery”… Whatever…

The IEA has recently published it’s new World Energy Review and if you have been reading this blog this comment will come as no surprise:

One notable trend concerns the relationship between oil prices and upstream costs. In the past, there has been a roughly linear relationship between upstream costs and oil prices. When price spiked, so did costs, and vice versa. What we are noting now is a decoupling. While prices have more than doubled since 2016, global upstream costs have remained substantially flat and for 2018 we estimate those increasing very modestly, by just 3%. Companies appear to have learned to do more with less.

Too many business models in the offshore supply chain are simply ignoring this. If you are going long on Borr Drilling shares (for example), as anything other than a momentum trade, then you need to look at data driven forecasts like this, which in statistical terms are called a structural break. Look at the cost deflator in the graph above! In an industry with high fixed costs (both original and operating) that is a straight financial gain for E&P companies and with the volatility in the oil prices they will not give that up easily… and in a world of oversupply they won’t have to.

The future will be different. Some vast market snapback where the Deamnd Fairy appears, and everyone brave enough to have paid OpEx in the offshore supply chain has found a clever get rich quick scheme, is an extremely unlikely event.

More data points like this should make you think as well:

IEA Source.png

Yes, I get the volume in absolute terms is growing, but it is change at the margin that defines industry profitability.

There is still too much liquidity and too many business plans talking as if a return to 2013/14 is a certainty when in reality such a scenario would be an outlier.

Change at the margin… shale versus offshore…

Shelf Drilling US.png

The map above and the statement above are taken from the Shelf Drilling prospectus. According to management, as can be clearly seen, there has been a structural change in the market and it simply isn’t coming back. 28 jack ups gone. Forever.

My only point on this is when you read about 90 units being scrapped since 2014 and 31 this year alone that is good in terms of helping restore the demand supply balance. But a market that used to have 40 jack-ups at it’s peak is never coming back and could conceivably go to zero. 1/3 of the scrappings just reflected a decline in the size of the market. And Mexico isn’t looking good either. Strangely none of the waterfall charts that show scrapping add back in an allowance for the accepted end state of the US Gulf? So of the 285 jackups on contract 10% of that number have had their market permanently removed and must surely impact on any credible scenario of market recovery?

Yes many in the GoM will have been the ones scrapped and will have been the older and less capable units, certainly not premium. But the point is there has been a structural change due to shale that has removed an geographical segment of the jack-up market and those need to be accounted for in a simplistic scrapping scenario. It also mean that if the market is “certain” to double in five years then other areas actually need to grow proportionately more to pick up the slack?

There has been a structural change in the Gulf market. Shallow water is out and large fields are in. Many of the offshore guys have probably gone onshore for the same money and the expense of laying off-take infrastructure in shallow water just isn’t worth it for companies now. This is a unique feature of the Gulf, although in Mexico they also appear to have largely exhausted the shallow water fields, but a factor with utilisation and supply/demand balances for the entire global fleet.

For those hoping for some Mexican respite this article from the FT last week will not be good news quoting the almost certain-to-be new finance minister:

“We certainly want more and more foreign, not just Mexican, investment and we’re going to open the door to everything,” Carlos Urzúa told the FT.  “The only exception is that there’s going to be a halt to oil tenders, ” said Mr Urzúa, an economics professor and published poet with a doctorate from the University of Wisconsin-Madison. “But apart from that, anywhere they want to invest, let them invest.” [Emphais added].

The growth in the GoM is all deep water high-flow rate, high CapEx projects. None of those can be serviced by jack-ups and given the international scope of companies like Rowan and Ensco some units are clearly destined for international markets.

This is just a small example of how small change at the margin affects the overall picture of demand for offshore assets. In 2014 the US was 14% of the jack-up market according to the figures above and recovery boom in the years ahead when the market has contracted meaningfully will be a rare feat if it occurs.

More of the same…?

There are two reasons why the world has lost confidence in forecasts. First: the record is awful. Remember the predictions of oil at $200 a barrel or the view that nuclear energy would be so cheap that no one would bother to meter its use?

The second reason is that events, especially around technology, are moving so rapidly that it is difficult to keep up with what is happening already, never mind what could come next. Artificial intelligence, energy storage and, at a very different level, the spread of religious fundamentalism are all potential game changers in the energy market. Yet predictions of how and when their influence will be felt are no more than guesses.

Nick Butler

Professor and chair of the Kings Policy Institute at Kings College London

GS oil price 18 June 19.JPG

Goldman Sachs, 18 June, 2018

In our Lower 48 business we co-developed a pad optimisation mathematical model with a Silicon valley start-up. This is the first time it has been applied in the Oil and Gas industry. When initially deployed on 180 wells and five pads, it reduced emissions by 74%, increased production by 20%, and reduced costs by 22%.

Lamar Mackay, BP Upstream CEO


The graph at the top is the IEA’s forecast for the oil price in 2019. I don’t get caught up on forecasts because for obvious statistical reasons they have a low probability of being correct, but they interesting in that they reflect the current “dominant logic” or investment narrative.

Brent crude averaged $54 per barrel in 2017 so obviously a near 30% price increase is good news for the beleagured offshore industry. But I am struggling to see a breakout here which isn’t just more of the same where a little incremental revenue gets added each year? At the moment volume also appears to be increasing more than value in the offshore industry (i..e companies are doing more for less).

There is optimism in the jack-up market though… investors are throwing money at jack-up companies that are promising not to return money in dividends (or indeed any form of capital repayment) and build market share in a highly fragmented industry. I struggle to see how these companies can in effect be adding capital to an industry when the majority of their customers are trying to reduce capital intensity? It is an odd dynamic where they are buying jack-ups for 30% less than cost despite the fact that in the old days utilisation used to be between 90-100% and now it is accepted it is much lower. A jack-up with only 8 months work is worth more than 30% less than one with 12 months work given the high fixed costs and the same day rate… and yet day rates are still under pressure and still the deliveries keep coming.

More later when I have more time but I think this is becoming an irrational market if demand stays at these sorts of levels. The ability of E&P companies to force time risk back to asset owners marks a fundamentally different industry in terms of structural profitability potential to one that existed in the past. I get scrapping reduces net units in the market but with the fleet utilisation of around 50% there is a lot to go and the option costs of these companies without significant work is very high in cash terms…

Anyway these forecasts are important in that about now E&P companies are starting to set budgets for 2019 plans. Based on the sort of forecasts you can expect only a marginal increase in spending and in offshore that isn’t what a lot of business plans want or need.

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

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

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

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

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

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

BH rig count 11 May 2018.png

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


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

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


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

Jackup and rigs 11 May 18.png

Source: Pareto Securities.

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

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

Transocean Iron Law.png

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

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

Bourbon Q1 2018 Susbea.png

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

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

Technip Q1 2018.png

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

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