Deflation, Shell, and Bourbon…

Shell gave a strategy update this week (the graphic above is from the presentation). More of the same really if you read this blog: more investment in shale and targeted and steady investment in offshore:

Shell 2025 outlook.png

And you can see the effect that over time Deep Water will be an increasingly smaller (but still important) part of production at Shell:

Shell 2025 Investment Tilt.png

But there is a clear tilt to shale and power. Yes they are spending more but the supply chain aren’t getting it:

Shell cost reduction to 2025.png

Shell Vendor Spend.png

For the offshore supply chain this is a very different world because a large number of the assets were acquired when that 2015 number was sloshing around the industry along with all the other money. Boats and rigs were ordered with 2015 dollars in mind and those days are long gone.

This is an age of deflation. Oil companies can, and have, sustainably changed the cost of production and met long-term demand expectations. The last offshore asset price bubble required both a demand boom and a credit boom. The demand boom has clearly gone and instead of the credit boom were are starting to see a credit contraction in a meaningful sense.

Slowly banks are realising that when the industry declines this much they don’t own and asset (loan), all they really own is a claim to the economic value an asset can produce. For all offshore assets that is much lower now than it was in 2015, and therefore those assets are not going to pay back anything like all the money they owe in an accounting sense. Slowly some banks stop rolling over credit, as has happened with DOF and Solstad among other firms, and the liquidity really starts to dry up.

The smaller banks are trying to force the larger banks to buy them out of these positions. This is clearly what is happening at DOF and Solstad. The larger banks in these deals will have to double down or accept large write-offs. In addition the number of hedge funds and other who have lost money on asset recovery plays is now so large that selling these deals is all but impossible (see Seadrill). Easy to get into but very hard to get out.

Bourbon creditors appear to have realised this.  A restructuring proposal has been sent to the Board for consideration. In reality the default is so large the creditors own the company. The creditors will write down billions of debt, Bourbon will reappear as a new financial entity, looking operationally a lot like the old, but like everyone else in the market believing their assets must be worth at least what they restructured them at. Capacity will be kept high and competition will ensure rates continue at below economic levels. It is a parable of the whole industry at the moment which shows no sign of abatement. Watching with interest DOF and Solstad because the larger Nordic banks stand to lose some real money here and yet the investment required to go on pretending would seem untouchable to any serious investor without write-offs in the billions of NOK from the banks. As offshore supply leads so will the rig companies as the head for their second round of restructurings (who inexplicably still seem to have access to bank financing).

But this is crazy world we live in. Much like the dotcom boom people are going to ask one day how they ever put money into a shipping company that excluded the cost of running a ship from it’s reported numbers:

  1. Positive EBITDA (adj.) of USD 617 thousands, excluding start-up cost, dry dock, special survey and maintenance (Q1 18 USD 400 thousands) from chartering out the 5 large –sized PSV’s. Including the ownership in Northern Supply AS (25.53%) the group netted a positive EBITDA (adj.) excluding start-up cost, dry dock, special survey and maintenance of USD 518 thousands (Q1 18 USD 200 thousands).

This isn’t going to happen quickly. Credit effects take significantly longer to work through than demand side effects. Once these banks have written off loans in a meaningful sense getting them to lend against these assets again will be nearly impossible.

And yet the cost pressure will continue:

Shell Cost pressure.png

E&P versus offshore strategy plans… Not what you think?

Last week ExxonMobil released its analyst day presentation. It has a number of interesting things, but I wanted to highlight the fact that although it feels like E&P companies are back making real money, which they are, it may not feel like that to them. And as this article on Bloomberg makes clear investors in these companies want management to keep the lid on CapEx, which is one of the cash flows they really can control:

Exxon argues it has a formidable set of projects, pointing to such goodies as offshore Guyana discoveries, as well as the Permian basin. The problem is that investors have seen this story before, and quite recently, with the oil majors. And while Exxon’s reputation might once have enabled it to simply be trusted to deliver, that is no longer the case.

Here is a Bloomberg shot showing you what would have happened had you purchased 1000 ExxonMobil shares in 2013 and sold at the end of 2017 (about when plans were probably being agreed):

image.PNG

You were down fractionally in the share price and up overall marginally only after reinvesting dividends. So the Directors are probably not coming under massive pressure to throw more money at production when 4 years after the price slump the owners of the ExxonMobil are trading below their 2013 entry cost (or fund market value). This is very oversimplified, but I make the point only because it has become an article of faith amongst some in the offshore space that E&P companies are verging on the irrational by not increasing offshore project spend when it is far from clear they are, or that they face pressure to do so.

Which is why you end up with a slide like this from a company that has just made some huge offshore discoveries:

Disciplined value.png

ExxonMobil focuses on Brazil and Guyana in terms of offshore development. I think the larger E&P companies switching to larger developments only offshore continues to mark a real shift in the market because the smaller companies just don’t have access to the development funding they used to for smaller fields.

I thought this was interesting:

XOM Guyana.png

Versus shale:

XOM tight oit.png

ExxonMobil appears to be implying shale has a lower breakeven pricing at $35 to get to a great than 10% return? And as always productivity is increasing:

XOM productivity increase.png

The other thing that struck me about the presentation was just how many investment opportunities management have across the portfolio, and they are increasing CapEx across the forecast period from USD 24bn to USD 30bn, but it is clear that downstream and other activities are also important. Investors want growth but maybe some at lower volatility that a fluctuating oil price offers, and as this graph shows ExxonMobil will make money at USD 60 ppb oil, but not ridiculous amounts.

XOM Fundamental.png

Obviously XOM is a leveraged bet on the price of oil increasing. But at the moment the upstream managers probably feel they have a free option on the excess capacity in the offshore supply chain that means any rapid price increases can be met with shale and a slower commissioning pace of offshore fields. Also these larger discoveries allow greater flexibility to speed up infield developments at a lower cost and asset utilisation.

Bourbon Offshore recently released it’s Bourbon in Motion strategy which to my mind is one of the most honest assessments of the scale of the challenge facing offshore companies I have seen. I think Bourbon are well worth listening to because I cannot think of another company that has played the capital markets as well as they have in financing their operations. Here in 3 simple points is the problem every offshore company faces:

3 issues.png

And it was really nice to see it wasn’t followed by a slide which said “but we are doing lots of tendering”.

A little history is required: In 2008  Bourbon had €1.3bn in debt and was focusing almost exclusively offshore. The annual report for that year described the returns in the offshore business as “exceptional”, and like all good companies it took this as a price signal to invest and grow the business further. Bourbon did this, because as the financing market was so flush it could borrow a lot of money, by 2013 debt had increased by €1bn to reach €2.2bn and the Directors were so confident about the business they proposed a 34% increase in the dividend.

In 2013 and 2014, taking advantge of the exceptional sentiment in the market Bourbon sold, and then leased back, vessels worth €1.65bn to Standard Chartered and ICBC which also allowed them to write up the value of the rest of the fleet by €900m in value. It’s hard to overstate how good the timing of this transaction was, timed literally to perfection, as the vessel market peaked in value they got two banks to pay not only top dollar for the assets but lease them back at less than 11% per annum. I doubt if sold on the open market here these now commodity vessels would fetch a third of that.

I am not implying Bourbon knew this would happen, what I am saying is they worked out that perhaps this was as good as it was going to get in the industry and they should bank what they could and take some (more) money off the table for their shareholders. As a management team it made them look very smart.

So when Bourbon tell you things are grim I think it comes with a degree of credibility few can match. Particularly when backed by some solid data:

The worst crisis ever

Which we all know by now. As I have said here repeatedly understanding that CapEx expenditure is what drives utilisation at the margin, and therefore overall fleet profitability, is crucial. And the reason I used ExxonMobil above was to show that this CapEx number, which I call “The Demand Fairy”, is unlikely to miraculously change in the short-term.

Offshore will still be an important part of the energy mix, but the growth of shale, as the left hand graph below makes clear, is having a huge impact on vessel utilisation and therefore industry profitability:

Bourbon Offshore production.png

The region reserved for shale is an area 3 or 4 years ago most people investing in offshore would have believed their assets would be servicing. And when you rely on 75-80% utilisation just to break even that in effect changes the whole economics of the industry, because if it knocks even 10% utilisation back across the fleet everyone is struggling to break even on their assets.

The right hand graph shows the enormous drop in CapEx. The fact that more projects are being sanctioned but the spend is lower just highlights what company results are showing: the volume of work has increased slightly this year but the value being paid for it has not (or reduced in some cases). This is likely to be a structural feature of the industry going forward that previous margin levels will simply not recover.

Like everyone else Bourbon is making a play to drive down the cost of operation of its commodity assets and add more value to the value of its subsea assets through moving up the value chain. Across the industry an entire species of contractor that used to make a good living by supporting larger contractors now aims to do more projects directly with E&P companies. Bourbon, like others, will likely win some market share, but they will do this by competing on price and driving industry margins down overall. For Bourbon it will still feel like more revenue than running the vessel alone, and in the long run it maybe, but grow to big and the larger contractors will be unlikely to charter your vessels. That slow increase in the blue bar on the graph is a result of all this extra capacity coming to market on the contractor side and why good Bus Dev staff in the industry are still remarkably employable.

It’s a post for another day the problem for offshore demand in shallow water, where projects could be done by flexibles and a vessel-of-opportunity, is that the smaller companies who used to do these projects simply have no access to the capital markets. Capital markets prefer smaller projects to be shale-based now where the cash-flow cycle is shorter. Think of the last time an Ithaca Athena development was commissioned on the UKCS?

Obviously the E&P companies are doing better than the offshore supply chain, the point is that they are not doing so much better that things are likely to change immediately. Bourbon seems to realise the future may look a lot like the present on the demand side and adjusting its business model accordingly.

(Hat-tip: SE).

 

Shell and Bourbon: a tale of two cities

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

A Tale of Two Cities

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

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

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

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

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

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

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

Shell Dividends

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

Shell Capex.png

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

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

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

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

Shell also noted geographically their commitment to deepwater:

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

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

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

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

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

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

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

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