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:

IMG_1067.JPG

…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

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.

Fundamental change or short-term shock?

The most popular letter in the FT today compared the review of Crude Volatility by Robert McNally (a Bush adviser) by the FT Energy Correspondent, Anjli Raval, to The Price of Oil by Roberto F Aguilera and Marian Radetzki. Basically, McNally argues we are in for a wild ride on prices and supply while Aguilera and Radetzki come in for shale and technology and permanently low prices. The writer agrees with fracking our way to salvation and permanently lower prices.

I read the read the review and admit McNally lost me with this:

But industry attempts to tame the market in the past have either had minimal success or been defied. The arrival of US shale in recent years has rendered Opec unwilling or unable to control the market, McNally says. With Opec’s power ebbing, “we are going to be unpleasantly surprised by chronically unstable oil prices”.

Come again? Normally getting rid of a cartel stabilises prices and lets market forces determine supply and demand? I couldn’t be bothered to read the book based on the review because it all sounded a bit contrived: you cannot control a cartel with that many players (as Opec is finding out), and as the famous Hunt Brothers (oil men to the core) discovered you can’t control a complex market like silver (or oil I’m betting on).

I haven’t read Aguilera and Radetzki’s book either, but they have a lot of stuff on the web that makes their view clear (at Vox and Scientific American). As they say here:

Using simple and reasonable methodologies, we estimate that the shale revolution outside the US will yield an additional 20 million barrels per day (mbd) by 2035 – nearly equal to the rise in global oil production over the past 20 years.

And look how much the cost curve for shale has changed since they published this in 2016:

Cam Rystad

The cynic in me naturally errs to favour technology over political market determinism in as much as I get concerned about these things. I guess that makes me long shale in my views. I still think offshore will be a major part of the energy supply mix (as the above chart makes clear), but perhaps less a part of the overall portfolio than we hoped in the near distant past.

Bourbon results offer no comfort or light

Bourbon released numbers this week that were bad, this isn’t an equity research site so I don’t intend to drill through them. Bourbon is a well-managed company and there is little it can do given the oversupply. But I can’t look at these stats without feeling like the HugeStadSea merger was too early. And quite how NAO, with 10 PSVs, raised money at USD 15m per vessel when the industry is at this level also looks like a triumph of hope over data. Subsea looks just as bad.

First, I think the graph below (from the Bourbon presentation) is telling and worrying for offshore. One of my constant themes is productivity. Shale is generating increasing productivity (i.e. constantly reducing unit costs) from all this investment, offshore fundamentally isn’t. The cost reductions from offshore are the result of financial losses, not more outputs from unit inputs.

Capital Investment Forecast: Shale versus Offshore

Capital Outlook

Clearly, the capital increase is good for vessel owners, but as this graph shows, the fleet was built for much better times.

Global E&P Spending

Global E&P Spending

And as the Bourbon numbers show, demand isn’t going to save offshore because the supply side of the market is too overbuilt.

Stacked vessels

The subsea fleet globally looks just as bad. Rates are only just above OPEX if you are lucky and nowhere near enough to cover financing or drydocking costs. The hard five-year dry-dock is the real killer from a cash flow perspective.

In order for this market to normalise not only vessels, but also capital, needs to leave the industry. I was, therefore, surprised that NAO raised USD 47m to keep going. NAO have 10 vessels, and are clearly subscale by any relevant industry size measure, are operating well below cash breakeven including financing costs (USD 11 500 per day), and still, they plow on. I understand it’s rational if you think the market is coming back (and the family/management put real money into this capital raise), but if everyone thinks like this then the market will never normalise. And when Fletcher/Standard Drilling can keep bringing PSVs back into the market at USD 8-10m, that do pretty much the same thing as your 2016 build, and 1/3 of the fleet can be recommissioned, the scale of a spending increase needed to credibly restore financial health to operators looks a long way off. Someone is going to have to start accepting capital losses or the industry as a whole will keep burning through new infusions of cash on OPEX. ( I know PSV rates, in particular, have increased this week but this looks like a short-run demand as summer comes and vessels come out of lay-up than a recovery.)

Specialty tonnage, such as DSVs, are in a worse position because as Nor/Harkand are showing people are reluctant to cold-stack due to the uncertainty of re-commissioning costs. Project work simply isn’t returning to at anything like the levels needed to get vessels and engineers working. Subsea construction work significantly lacks rig work, and companies are delaying maintenance longer than people ever thought possible.

Rig Demand

I think restructuring, consolidation, and capital raising are clearly the answer don’t get me wrong. I just think some falling knives have been caught recently (the Nor/Harkand bondholders being the best example) and the industry seems reluctant to admit the scale of the upcoming challenge. And again I am perplexed why the Solstad shareholders allowed themselves to dilute their OSV fleet with greater exposure to supply, when the dynamics are clearly so bad? The subsea and offshore industries appear to be facing structurally lower profits for a long time, and more restructurings, or a second round for some, seem far more likely than an uptick this year and next.

 

Increased offshore expenditure not sufficient to change inevitable consolidation and shake-out

Rystad Energy have a good article on offshore CAPEX versus North American Shale. I am not sure it offers a huge degree of comfort for offshore contractors and vessel owners:

  1. 70% of expenditure comes from 10 projects (most of which were in planning long before the current downturn). Should this pattern continue the industry would become dominated by a few large contractors that worked on mega-projects only. The entire ecosystem of smaller contractors would be reduced to servicing these large EPIC contractors at hugely reduced margins and competing fiercely for IRM work to keep utilisation high. The sheer scale of these types developments favours large well-entrecnhed competitors with links across the value chain to subsea processing companies. Again the space for smaller firms is likely to be limited to subcontractors only
  2. As noted above these were all sanctioned and had final investment decisions some time ago. Large, high volume and low OPEX, deepwater fields are likely to be the core of offshore demand going forward. GIven the lead bid times the projects being bid now are likey to be extremely margin compressed for years to come, so an increase in the oil price will drop straight to the E&P company bottom line without helping the offshore fraternity at all. Time is not the friend of those long on ships and drill rigs at the moment
  3. Given current industry supply levels these larger contracting entities will likely be more “asset-light”, apart from core delivery assets, than we are used to. This is likely to result in continued, and long-lived, margin erosion for anyone apart from a tier 1 offshore contractor. If you want an unbiased example of this look to the civil contracting industry where anyone other than the prime contractor makes operating profit at close to marginal cost
  4. Jusr as importantly the pick-up in demand, if indeed it is that, has occured only by a decrease in offshore and subsea rates below what it is economically possible to supply in the long-term
  5. 3-4 large contractors, and Technip, Subsea 7, Saipem, and McDermott (with limited asset and competitive differentiation) will all be there, with some strong regional players, is enough to drive industry margins down to normal economic profit for the foreseeable future

Rystad mention the drop in drilling and offshore subsea rates, but everyone is operating at below cash break even on projects at the moment to win work. Currently in order to fund this cost deflation all drilling operators of note are refinancing and the loss in equity has been huge, and a somewhat more delayed pattern is also occurring in the OSV market. It would not appear that demand and supply are therefore balanced, or even close to it. All it indicates is the brutality of the E&P supply chain and the willingness of offshore contractors, long on fixed assets with high running costs, to bid at whatever it takes to win some work and try and last longer than anyone else.

The market would appear to be some way off equilibrium. The graph at the top is the Subsea 7 (orange line) share price versus Solstad (blue line) over the past 12 months, essentially a proxy for my thesis above (in the most general sense and picked because the weight of their relative debt should strengthen my argument and magnify equity returns), and it would appear the market consensus is similar to mine.