“Short-cycle production” could be about to get an economic test…

The dots clearly show that oil prices and oil production are uncorrelated…

Caldara, Dario, Michele Cavallo, and Matteo Iacoviello

Board of Governers of the Federal Reserve System, 2016

The number of US oil rigs went down by 5 last week to 744 rigs, while the number of US gas rigs increased by 4 to 190 rigs. In terms of the large basins, the Permian rig count increased by 6 to 386 rigs, while both the Eagle Ford and Bakken rig counts declined by 3 each to 68 and 49 rigs respectively. 

Baker Hughes Rig Count, Sep 25, 2017

 

The multi-billion dollar question is: Can shale handle an increse in demand? Closely related: Is shale in a boom that is unsustainable and not generating sufficient cash to reward investors for the massive risk they have taken? Because if the latter is correct the former must be answered in the negative. The above quote is slightly mischevious and merely highlights economic research that supply factors have historically had a far bigger impact on the oil market than demand factors  (whether this is true going forward is not for today).

The NY Fed today reports that it is supply shortages now that are driving the price (and I have no idea about the construction of the model but the reduction in the residual leads me to believe it is broadly accurate), so this is a supply driven event not a demand driven event:

Oil Price Decomp 25 Sep 2017.png

If, as Spencer Dale argues (speech here), we are in the midst of a technical revolution then this is what we would expect. Hostoric levels of inventories should come down because supply is more flexible, these short-term kinks in demand caused by natural or geopolitical events should merely spur an increase in the rig count or a change in OPEC quotas. Other senior BP staff today were on message:

“Rebalancing is already on the way,” Janet Kong, Eastern Hemisphere Chief Executive Officer of integrated supply and trading at BP, said in an interview in Singapore. But OPEC needs “definitely to cut beyond the first quarter [2018]” to bring inventories down and back to historically normal levels, she said…

“If they extend the cuts, yes it’s possible” to achieve $60 a barrel next year, she said. “But it’s hard for me to see that prices will be sustainably higher,” she added.

Or is Permania simply the result of the Federal Reserve flooding the market with liquidity that is allowing an unsustainable production methodology to continue unabated storing up yet another boom and bust cycle? Bloomberg this week published this article on Permania, where the incipient signs of a bubble are showing in labour and infrastructure shortages and the outrageous cost overruns:

Experienced workers are harder and harder to find, and training newbies adds to expenses. The quality of work can suffer, too, erasing efficiency gains. Pruett said Elevation Resources recently had a fracking job that was supposed to take seven days but lasted nine because unschooled roughnecks caused some equipment malfunctions.

By this point, “we’ve given up all of our profit margin,” he said, referring to the industry. “We’re over-capitalized, we’re over-drilling and, if prices don’t rise, we might be facing a double dip in drilling.”

If I was being cynical about offshore production I would note that he was two days over with a rig crew while in the same calender week Seadrill and Oceanrig had collectively disposed of billions of investment capital and will still have the inventory for years. This guy is literally two days out of forecast and he is worried about being over-capitalized (and also that wiped his profit margin? Hardly redolent of a boom?) Offshore drilling companies are like 10 years and 100 rigs out of kilter… Anyway moving swiftly on…

Bloomberg also published this opinion on Anadarko noting:

Late on Wednesday, Anadarko Petroleum Corp., which closed at $44.81 a share, announced plans to buy back up to $2.5 billion of its stock; which is interesting, because almost exactly a year ago, it sold about $2 billion of new stock — at $54.50 apiece.

(That’s pretty clever, they sold stock at $54.5 and are buying it back at $44.8, like Glencore never buy off these people when they are selling, at heart they are traders. More importantly most research suggest companies nearly always overpay when buying stock back so if the oil price keeps creeping up they are going to look very smart indeed.)

But the real point of the story is that capital is slowing up to the E&P sector, well equity anyway no mention of high-yield:

Equity US E&P Sep 2017

Meaning that maybe people are getting sick of being promised “jam tomorrow”. However I can’t help contrasting this with productivity data, Rystad on Friday produced this:

Rystad Shale Improvement Sep 17

So despite the anecdotal evidence on cost increases in the first Bloomberg article the productivity trend is all one way.  And the stats seem clear that a large part of deepwater is at a structural cost disadvantage to shale:

ANZ cost structure 2017

Frac sand used to be c.50% of the consummables of shale, but surprise:

Average sand volumes for each foot of a well drilled fell slightly last quarter for the first time in a year, said exploration and production consultancy Rystad Energy. Volumes are expected to drop a further 2.5 percent per foot in the current quarter over last, Rystad forecast…

Companies including Unimin Corp, U.S. Silica Holdings Inc (SLCA.N), and Hi Crush Partners LP (HCLP.N) are spending hundreds of millions of dollars on new mines to address an expected increase in demand.

On Thursday, supplier Smart Sand SND.O reported it shipped less frack sand in the second quarter than it did in the first. Rival Fairmount Santrol Holdings Inc (FMSA.N) forecast flat to slightly higher volumes this quarter over last.

In the last six weeks, shares of U.S. Silica and Hi Crush are both off about 30 percent. Smart Sand is off about 43 percent since June 30…

Some shale producers add chemical diverters, compounds that spread the slurry evenly in a well, and can reduce the amount of sand required. Anadarko Petroleum Corp (APC.N) and Continental Resources Inc (CLR.N) are reducing the distance between fractures to boost oil production. The tighter spacing allows them to extract more crude with less sand.

Technological innovation and scale: Less sand used and increased investment going on that will reduce the unit costs of sand for E&P producers. This is the sort of production that brought you the Model T in the first place and the American economy excels at. Bet against if you want: just remember the widowmaker trade.

Shale is a mass production technique: eventually it will push the cost of production down as it refines the processes associated with it. To be competitive offshore must emulate these constantly increasing cost efficiencies. I have said before that shale won’t be the death of offshore but it will make a new offshore: a bifurcation between more efficient fields, low lift costs, and economies of scale in production that make the “one-off” nature of the infratsructure cost efficient, and smaller, short-cycle E&P of shale (and some onshore conventional).

Offshore is going to be here for a long time, it is simply too important in volume terms not to be. But what a price increase is not going to see is a vast increase in the sanctioning of new offshore projects in the short-term. These will be gradual and provide a strong base of supply, as there longer investment cycle represents, while kinks in short-term demand will be pushed towards short cycle production. Backlog, or lack thereof, remains the single biggest threat to all offshore contractors.

Or this thesis is wrong and I, and to be fair people far cleverer (and more credible) than me, are spectacularly wrong, and a new boom for offshore awaits in the not too distant future…

The narrative in capital allocation moves to shale…

I use the term narrative to mean a simple story or easily expressed explanation of events that many people want to bring up in conversation or on news or social media because it can be used to stimulate the concerns or emotions of others, and/or because it appears to advance self-interest. To be stimulating, it usually has some human interest either direct or implied. As I (and many others) use the term, a narrative is a gem for conversation, and may take the form of an extraordinary or heroic tale or even a joke. It is not generally a researched story, and may have glaring holes, as in “urban legends.” The form of the narrative varies through time and across tellings, but maintains a core contagious element, in the forms that are successful in spreading. Why an element is contagious, when it may even “go viral,” may be hard to understand, unless we reflect carefully on the reason people like to spread the narrative. Mutations in narratives spring up randomly, just as in organisms in evolutionary biology, and when they are contagious, the mutated narratives generate seemingly unpredictable changes in the economy.

Shiller, 2017

News that BP had started production at Quad 204 (Schiehallion) led curmudgeonly FT columnist Lombard to note  yesterday:

If anything, then, Monday’s news is more of a last hurrah for BP in the North Sea, and for the UK Continental Shelf more broadly. With the strongest capital flows — and investor buzz — focused on unconventional US resources, traditional offshore oil can seem as fashionable as a set of free “crystal” tumblers from a 1970s petrol station. With a big shield logo.

I have mentioned here before that behavioural finance is starting to examine the narrative in economics (see initial quote), and at the moment this is the narrative in London and other capital markets. This ties in nicely with an excellent piece from Rystad earlier in the week looking at the future of the North Sea and the Gulf of Mexico (I recommend reading the whole thing). For service companies Rystad notes:

After such a deep cut in this market it will take some time before the industry experiences a full recovery. Even with oil prices of $90/bbl to $100/bbl for the next decade, the market will not be back to 2014 levels before 2024.

The link for me is that offshore is going to bifurcate into huge developments (Quad 204, Mariner, Bressay, Mad Dog 2) and “the rest”. The rest are unfortunately going to be much smaller in number and less frequent. Rystad specifically mentions the lack of tie-back and tie-in projects in these regions. These projects are the investments that really compete with shale: 8-12 000 bpd that were ignored by larger E&P companies. The larger developments with high flow rates, and multi-decade economic plans, are vital for security of volume and a core underpinning of E&P profitability, and they are very economic, playing to super-major strengths of vast capital requirements combined with astounding engineering capability; but smaller developments in the USD 50-200m range are at a real risk of grinding to a slow halt for all except the companies currently committed to this space.

The North Sea, and to a lesser extent GoM, always had a significant number of smaller players (think Ithaca Energy (recently sold to Dalek) or Enquest), that raised (relatively) small sums of money and then sought to regenerate an exisiting area or develop smaller finds. Access to financing for that market simply doesn’t exist at the moment on anything like the scale it did before. Those Finance Directors who used to traipse around fund managers in London, Vancouver, New York etc with a deck of slides explaining their proposed developments are simply not getting a hearing. Not only that the tried and tested business model of developing a few fields and selling out with a takeover premium when they had built sufficient scale isn’t credible any more as potential acquirers focus on more on tight oil. Now those fund managers are meeting with guys who have a deck of slides that start with a shale rig, emphasise the relatively low upfront capital (as opposed to the higher OpEx) and their ability to rein in variable costs should price declines occur. The meme in financial markets now is all about shale, and rightly or wrongly, influential columns such as the one above help set this “dominant logic”.

Inside the big E&P companies managers, who are cognizent of the fact they must deal with analysts in the financial community and the investor base who follow the same narrative, are adapting and spending more time to examining potential shale investments. Offshore is getting less airtime. When was the last time you hard someone say “all the easy oil is gone” – which was taken as fact only 5 years ago. From this myriad of individual meetings and actions the macro picture of slowing capital flows into offshore and increased investment in shale is being driven, and it will be very hard to reverse without some exogenous event.

As behavioural economics teaches us humans are “boundedly rational” not the perfectly rational homo economicus so beloved of the efficient markets crowd. What this means is that potential investors can only process so much information, if you combine this with the fact that institutional investors “herd” (i.e. invest where their competitors do), you can see the current investment vogue is short cycle shale which makes even getting funding hard even for compelling offshore investments. Those who have heard the word “Permania” used to describe the boom in Permian basin will relate to this quote from the IMF on investment herding:

[p]rocyclicality in asset allocation can make swings in financial asset value and economic activity more intense. From an individual investor’s point of view, procyclical behavior can be rational, especially if short-term constraints become binding or if the investor can exit earlier than others. However, the collective actions of many investors may lead to increased volatility of asset prices and instability of the financial system..

Eventually the shale mania will wain as people overpay for land and productivity improvements slow. The problem for offshore is the amount of OpEx people will have to burn to get to this point and the consistently increasing productivity of shale.

Big players in the North Sea region like Apache, Taqa, and Sinopec will conitnue to develop offshore fields but they are not doing as many projects. The threshold rate for investment will be higher, because experience has taught us that you can get 5 years of low oil prices and many of these projects only have economic lives of 5-10 years (risk models are great at solving previous issues). These companies have less access to capital markets than their shale competitors because the high-yield desk has the same meme as the equity investors, higher equity costs and more risk averse bank funding raise project return requirements even more. Even state -backed companies like Taqa must vie for funding internally. Outside of the North Sea and GoM these developments are likely to remain dominated by National Oil Companies who may not rank projects on a strictly economic basis but will take the expected spot price of oil into account in their investment decisions. But as Rystad makes clear the North Sea and GoM volume increases will all be driven by a smaller number of larger projects.

This affects contractors differently. As Rystad notes EPIC work will decline proportionately less than other work.  For DSVs and ROV operators and vessel owners) this is grim . Until construction work, that uses far more DSV and ROV days than maintenance work, improves the supply side of the industry will take the adjustments both in day rates and utilisation levels. The supply chain is going to change into a few large integrated contractors in these regions with a vast choice of assets to service their needs and they are likely to reduce their comitted charter tonnage . These large contractors will make an economic return but part of it will be done by ensuring the smaller companies in the supply chain make only enough economic profit to survive and the equity value (if any) in these companies and assets looks set to be depressed for an extended period. Consolidation on a scale only dreamed of at the moment amongst vessel owners looks certain.

Demand will not return for smaller projects until the market price for oil stabilises at a substantially higher price than now, and does so for long-enough to give potential funders confidence that the upturn isn’t temporary. The uplift will likely be less severe because shale has introduced a “kink” in the supply curve. Projects take time to pass through engineering, funding etc before meaningful offshore work occurs. This is a long-term issue: Demand may have stabilised at current levels but recovery for the supply chain that is based on the realistic prospect of higher days rates and utillisation looks some way off.  For an asset base built to supply a 2013/14 demand curve the outcome looks uncomfortably obvious.

 

 

Low order backlog defines and highlights lack of current subsea recovery

Three companies that define the subsea industry reported numbers this week: Saipem, TechnipFMC (imagine if they had brought CGG!), and Subsea 7. All were widely varying but the clear theme of overcapacity/ underutilisation remains with subtle variations. Clearly the place to be if possible is light on core assets and long on engineering and execution capability if possible. The core question for the subsea industry remains what proportion of oil demand will be met by offshore production fields (and to a certain extent what the growth of overall demand will be)?

On future market demand the IEA was in the press again today with this:

Less than 5 billion barrels’ worth of conventional oil resources were sanctioned for development last year, down from almost 7 billion barrels in 2015 and 21 billion barrels in 2014, the year oil prices began their slide. Approvals of offshore projects, which are typically more expensive, fell disproportionately, representing 14 per cent of new project sanctions compared with more than 40 per cent on average over the previous 15 years.

Spending on exploration is on course to fall again for the third year running, the IEA said, reducing it to less than half the level seen in 2014, when it stood at more than $120 billion (£92.9 billion).

I have said here before I don’t see offshore production going away. Offshore will clearly continue to be a crucial part of the energy mix. The question, as always, is how much share as the vessel fleet has been built for a far bigger proportion than is currently being demanded. I heard repeated again last week that underinvestment in the current cycle makes a snap back “inevitable” and when this happens offshore will boom again. I’m just not sure I agree as the supply side seems to be out of all proportion to the market and the working capital subsea companies need who are too long on vessels may make the gap too long to bridge given how long it takes for projects to roll out post FID.

While the IEA warns of the this investment crunch Spencer Dale, Chief Economist at BP, is far more sanguine. I quote this speech all the time but its worth requoting a core point:

The US shale revolution has, in effect, introduced a kink in the (short-run) oil supply curve, which should act to dampen price volatility. As prices fall, the supply of shale oil will decline, mitigating the fall in oil prices.

Likewise, as prices recover, shale oil will increase, limiting any spike in oil prices.

Shale oil acts as a form of shock absorber for the global oil market…

To be clear: shale oil is the marginal source of supply only in a temporal sense. The majority of shale oil lies somewhere in the middle of the cost curve. As such, further out, as other types of production have time to adjust and oil companies have to take account of the cost of investing in new drilling rigs and operating platforms, the burden of adjustment is likely to shift gradually away from shale oil towards other forms of production, further up the cost curve.

 

(Emphasis added).

This was written in 2015 and its obvious now that this is exactly what has happened. The sceptic in me struggles with the core logic that rational economic actors are prepared to forgo potentially huge sums by not investing now. If this was such a slam dunk case as the IEA make out then why don’t some smart private equity firms partner with big oil (for the technical skills) and simply develop these fields, when construction costs are at an all-time low? The answer is because it isn’t that simple I suspect.

I am basically a weak-form efficiency believer. I think the oil market is largely rational in the long-run. The long run is a sufficiently amorphous and indeterminate period of time to say that at certain times it can be “irrational” (i.e. USD 27 was to low, but USD 130 was too high), but on average it helps demand and supply meet. But I do realise that one of the problems in the oil market is that many investors in their equity buy them as a dividend stock. Despite the fact that the underlying commodity is extremely volatile in short term pricing (and is likely to be a random walk in anything other than a 1-2 year period), and that therefore E&P companies should really pay out dividends as a proportion of earnings, they quite simply don’t. To E&P companies the dividend is regarded as sacrosanct. Financial economists know this phenomenan well and its formal definition comes in the “Bird in the hand” dividend theory or the “Dividend Clientele Hypothesis“. BIH argues that investors prefer the certainty of dividends to future capital gains and the DCH argues that certain types of investors favour companies that pay dividends (often because of tax or investment mandates). I think they are both right and that the supermajor shareholders in the main are made up of these types of investors.

This means that E&P companies would forgo likely payoffs in the future to keep shareholders happy now (especially as they could fund future CapEx from higher future prices). So I get this could this be happening. And the downside of course is that if you are wrong, and you have made a superbet on this market shortfall in 2020 (or whenever), you end up with a 25 year asset in (e.g.) offshore Brazil that cost USD 3-5bn that you can’t shut down or exit easily that is producing 100 000 bpd at a cost greater than their economic value. Clearly these sort of risk probably work better as part of a portfolio play and hence why the super majors exist: they are an economically rational response to the market issues.

It’s within this context that the results of these offshore contractors need to be seen. The common theme across the industry is that backlog is not returning as quickly as offshore contractors are burning through current work. The other common theme I think is a flight to quality where E&P companies are engaging with tier 1 contractors more and the smaller players will find it increasingly hard. Smaller E&P players Technip and Subsea 7 would never have bothered to court are flattered when they are pursued by these companies offering them the full suite of their capabilities and assets.

Subsea 7 came in with really good EBITDA numbers; but they had the benefit of delivering projects bid at higher margins while procurement is being done at a low point in the cycle. But the other thing Subsea 7 has done really well is utilisation: with fixed vessel costs so high any extra days drop straight to the bottom line. Active utilisation of 65% for their fleet is exceptional in this market (compare to Oympic). I have no idea if this is an apocrophyl story or not but I was told a year or so ago that Kristian Siem instructed Subsea 7 management that he personally has to sign off on all vessel charters using third-party tonnage now, to encourage projects crews to use a Subsea 7 or Siem vessel. Even if its not true I think the mindset is and it fits in with what all the line managers are saying about Subsea 7 in the market: they are extremely aggressive on vessel days (for example remving the Pelican from cold stack for Apache in the North Sea). Don’t get me wrong it’s smart and necessary: Subsea 7, with 34 vessels, just have to get them working or they will have a credit event, and its good execution.

But the Seven Mar and the Seven Navica are in still in cold stack. The Navica in particular is a talisman for North Sea construction activity. Until that vessel is busy doing small scale field developments then by definition the North Sea (an UKCS in particular) will be oversupplied with DSVs and overly dependent on maintenance rather than construction work. The fact that these assets are in cold stack (and it’s not only Subsea 7) means there is an enormous amount of latent capacity in the sysytem that could respond to increased E&P demand very quickly. Portable lay spreads and ad-hoc systems (like the one on the Bibby Polaris) have also grown in number in recent years and could be quickly activated.

Saipem also came in with a poor order book at 0.2x book-to-bill (i.e. it replaced 20% of the revenue billed this quarter with new work). It can overshadow the fact that Saipem is still a really big company with an annual turnover of 10bn, a great franchise in some very difficult regions (which make it less margin sensitive), and a wealth of technical expertise. But the problem Saipem has is that it is an average drilling company and a quality subsea/ pipeline company. All the drilling companies are restructuring and coming back with very strong balance sheets for the next few years and Saipem has some major drilling contract renewals next year and its not hard to see revenue dropping like a stone in that business. Having raised €3.5bn in a rights issue Saipem then had to go back and write €2.1bn off (non cash), but it is trying to pay back its lenders 100c in € whereas all their competitors are engaged in debt-for-equity swaps. It’s totally unsustainable. Not like EZRA where it was obviously going to happen near term, this is a slow battle of attrition as more and more time and equity gets devoted to the Sisyphian task of trying to generate economic value with an overvalued asset base (in a relartive sense) that has a higher fixed cost base.

Which is a shame because the Saipem offshore construction business, with a fleet of quality assets, an eviable project track record, and huge intellectual capital, despite being buried in a Byzantine organisational structure, is a great business. With the right balance sheet and strategic direction the Saipem Offshore E&C business could be a world leader, it is long all the assets you can’t possibly charter (nor would you want to), such as heavylift and and pipelay (J and S), and long on engineering capability. Every other subsea asset you can be short on at the moment because the vessel market is oversupplied and will be for a long time. Even diving for shallow water construction can be handled internally with chartered tonnage.

There is no real resolution here. Saipem is reorganising (again).  But I doubt you could could realistically seperate out the different divisions in an equitable way from a capital markets perspective. From a subsea perspective the remaining three business lines (onshore and offshore drilling) will just detract from the potential of what should be a tier 1 powerhouse (even if it does make the Italian post office look efficient).

Which brings us on nicely to TechnipFMC… low order book in Subsea while reasonably good numbers. It is the industry bellweather at the moment, no one can do in deepwater what they can, and if they cannot replace their orderbook  the total addressable market will be smaller.

I’m clearly no expert on the oil market but it is clear that offshore investment does not appear to have stabilised yet. Until the core companies in the industry have reasonable amounts of backlog it is too early to talk of a recovery. And the IEA may be right that we are currently underinvesting, but for offshore the key is the snapback: if it comes, it is likely to be less dramatic for anyone who is too long on vessel capacity, but for those with delivery capability and intellectual property it is a different story.

“This time it’s different…”

“The four most expensive words in the English language are, ‘This time it’s different.’”

Sir John Templeton

In investment theory a key part of recognising that a bubble is close to bursting is the logic that “this time it’s different”, the internet boom of 1999-2000 being the classic case. The core argument is actually regression to the mean: eventually all profits drop back to normal levels, but this time, they won’t.

In oil services, particularly offshore, there seems a view that this downturn is the same as others. Everyone wants to believe that next time will be the same. Somehow, magically, demand will equal supply, day rates will rocket, and everyone will go back to building USD 100m vessels with USD 20m equity, to put on the spot market and and that will be the new normal. I think the narrative is driven by the extremely mild (in hindsight, it didn’t feel like it at the time) dip in 2008/9, and the strong recovery in 2000, where people who had invested early, and took serious risk, made some exceptional returns (Integrated Subsea Services springs to mind). It might happen, but I doubt it.

For one thing the daily fascination with the oil price seems entirely inappropriate for offshore contractors. The industry is wallowing in a sty of capacity: it’s the supply side that important in the short-run here not the demand side. As everyone in the industry knows (deep down) the number of project staff laid-off will ensure it would take a long time for the E&P companies to ramp up projects even if they wanted to.

The oil production industry is clearly undergoing a structural shift with the impact of shale. It won’t be the end of deepwater and offshore, but it seems unlikely to return as before. I wrote before about the changing economics of shale and the extraordinary drop down the cost curve that has affected that industry. My core point is that when you can drive standardisation you get massive efficiencies that can transform the cost curve, and therefore, the underlying economics of an industry.

In that vein, inspired by this piece from the FT (which is broadly dismissive of electric vehicles), I read this from the Grantham Institute. The report focuses on the Solar Photovoltaic and Electric Vehicle cost reductions that come from scale improvements in the manufacturing process and producitivity of the units (particularly battery efficiency for electric cars). Under their model oil demand peaks in 2020:

E[lectric] V[ehicle]s account for approximately 35% of the road transport market by 2035 – BP put this figure at just 6% in its 2017 energy outlook. By 2050, EVs account for over two-thirds of the road transport market. This growth trajectory sees EVs displace approximately two million barrels of oil per day (mbd) in 2025 and 25mbd in 2050. To put these figures in context, the recent 2014-15 oil price collapse was the result of a two mbd (2%) shift in the supply-demand balance.

Now there are a number of caveats in the research and I also get that they have an agenda. So of course does BP. No one is lying here,  it’s just that humans are “boundedly rational“; they can only process so much, and what they do therefore is referenced in cognitive analogies and models. The arguments form part of a “dominant logic” of analysis and decision making. Both are statiscally sophisticated models with regression analysis at the core and therefore one is reminded of the Great Man’s warning (to Koopman’s) on the problems with this sort of analysis:

Many thanks for sending me your article. I enjoyed it very much. I am sure these matters need discussing in that sort of way. There is one point, to which in practice I attach a great importance, you do not allude to. In many of these statistical researches, in order to get enough observations they have to be scattered over a lengthy period of time; and for a lengthy period of time it very seldom remains true that the environment is sufficiently stable. That is the dilemma of many of these enquiries, which they do not seem to me to face. Either they are dependent on too few observations, or they cannot rely on the stability of the environment. It is only rarely that this dilemma can be avoided.

Letter from J. M. Keynes to T. Koopmans, May 29, 1941

The point is I guess that somewhere between BP and the Grantham Institute we are likely, barring a major technological development, to see the outcome. But directionally the Grantham Institute research seems to be right side of change, and that is important when you see this graph:

Global Oil by Sector

In the long run I favour productivity and technical improvement over most other drivers in the economy. You can pass an inflection point where the whole economics of an industry changes. Shale has had it, and solar and EV might have it as well. But a core point is it requires standardisation and scale combined with technology improvements, and my worry for offshore is it has none of these except the potential of marginal improvements.

As I have argued offshore energy isn’t going to go away: in volume terms it too much of an important part of the supply chain for that. But is it going to be on the scale and have the importance it did before? BP and the other oil companies are right to keep investing, that is their business and their shareholders believe that, it’s capitalism, and a very efficient market mechanism. These productivity improvements are marginal at the moment, and car replacement cycles are long, competition is never stagnant etc. But it is hard to see a dramatic fall in the price of oil extraction productivity given it’s maturity (blended across production sources), and the same cannot be said for electric vehicle productivity. I accept that I have said that about shale, and there appears to be much further to run down the productivity curve, but subsea production is subject to dimishing returns, high capital utilisation, and asset productivity limits. Subsea is very efficient at scale but it is not easy to transform the limits of that scale, which isn’t true for manufacturing electric batteries and their potential capacity increases and price decreases (in real terms), and also to a lesser degree shale, which is limited by a high-service/labour input element.

There are issues with this negative theory: production that ends is harder to track and much less visible, I think I am biased by being amazed how quickly Tesla seems to to be growing, resource constraints could be found in battery manufacture etc. But it feels to me like we are passing a stage where after having been dependent on one source of energy for so long, admittedly a remarkable one on a calorie/output efficiency basis, other technologies are catching-up.

I don’t have a crystal ball, but going long on 25 year assets like drilling rigs and vessels, on the logic that it will always bounce back, because it did before, unless it’s part of a portfolio investment, strikes me as more risky than at anytime in the past 25 years. Whatever the industry will looked like in five years from now I doubt offshore will look like it did in 2013 ever again.

I’m a believer… just in something different…

A good FT article here about how oil and gas discoveries have recently fallen to their lowest levels ever. I’m with Spencer Dale and the shale crowd… it’s the marginal production expansion reserve of choice… but I’m also with offshore… I just think the next boom will be somewhat different and probably less of a boom.

However I also think the focus on Reserve Replacement Ratio (RRR) will also diminish somewhat and E&P companies will be more focused on other issues beyond discovery levels. RRR is a good concept when you are reaching the frontier of oil production, and certainly no one cared about it more than Exxon Mobil, but its a measure of interest really only when the entry and CAPEX costs of increased production are so high. Its not even a measure of exploration efficiency because companies that cut back offshore CAPEX clearly are not seeking to replace reserves 100%. RRR is a relic of bygone era when  you couldn’t drop a few billion and buy some decent shale acreage or a small Swedish start-up didn’t strike it big in the Barents.

Large E&P companies have shown in the downturn that they are committed to constant dividend payments, regardless of underlying cash flow generation where possible, and I think it likely reserves will go the same way: some years there will be a bumper increase and other years a decrease, the trend and stability more than the absolute limit will become important.

I mention this in the context of offshore because not only has shale changed the production economics (as I have discussed before) but also because it is likely to make a recovery from this offshore exploration trough slower than people would like. I do believe in offshore long-term… just the new offshore economics not the old.