Weekend shale read… The Red Queen for offshore…

“Well, in our country,” said Alice, still panting a little, “you’d generally get to somewhere else—if you run very fast for a long time, as we’ve been doing.”

“A slow sort of country!” said the Queen. “Now, here, you see, it takes all the running you can do, to keep in the same place. If you want to get somewhere else, you must run at least twice as fast as that!”

Alice in Wonderland, Lewis Carrol

Applied to a business context, the Red Queen can be seen as a contest in which each firm’s performance depends on the firm’s matching or exceeding the actions of rivals. In these contests, performance increases gained by one firm as a result of innovative actions tend to lead to a performance decrease in other firms. The only way rival firms in such competitive races can maintain their performance relative to others is by taking actions of their own. Each firm is forced by the others in an industry to participate in continuous and escalating actions and development that are such that all the firms end up racing as fast as they can just to stand still relative to competitors.

THE RED QUEEN EFFECT: COMPETITIVE ACTIONS AND FIRM PERFORMANCE

Derfus et al., 2008

 

Stressing output is the key to improving productivity, while looking to increase activity can result in just the opposite.

Paul Gauguin

 

The IEA has done a review of shale companies financing and for those hoping that they represent some sort of ephemeral phenomenon that will pass as soon as the junk bond market closes, well rates decline, or some other exogenous event arises, they are likely to be disappointed. It’s a short read and well worth the effort. I called shale an industrial revolution the other day and the IEA post is a good short precis on how this came about in financial stages.

SPE also has had some good articles recently on the constant productivity the shale industry is using to drive down costs. This one on Equinor for example:

One of the drawbacks of the status quo is that it requires small armies of field personnel to interpret SCADA data and then adjust set-points to get pumping units back into optimal operating ranges. This manual process can consume half-an-hour per well to complete; downtime that quickly adds up in a field of hundreds.

“What we are talking about is having the machine do that entire workflow,” Chris Robart, Ambyint’s president of US operations said…

The Bakken project comes after a pilot that included 50 of Equinor’s wells, which saw a net production increase of 6%—considerably larger uplift figures were seen from those wells suffering from under-pumping.

Or this one dealing with Parent/ Child wells, which a few months ago seemed to be the latest reason to explain why shale wasn’t a sustainable form of energy, but the industry has solved part of this problem through “cube development”:

But the prize for coining the term cube development goes to Encana Corporation, which says the strategy has increased early well productivity in one of its Permian fields by 70% over the past 2 years. Despite the term’s growing popularity within engineering circles, some companies continue to use different terms such as QEP’s “tank-style completions” for what is seen as the same general practice.

I don’t understand the technology but I have faith that day-in day-out new techniques are being developed that will drive down the costs of extraction and production in the shale industry. You need to be a technical pessimist, which in this age is hard, to believe this productivity direction cannot continue (see Citi here).

Over time the offshore industry will change to compete with shale. The economic force of competition will ensure this. But in order to compete it will need to reduce the cost and time of being offshore dramatically and focuson on high-flow low lift cost projects. Something well underway in the Gulf of Mexico at the moment.

There are huge moves in offshore to improve productivity: all righty focused on spending lowering cost and reducing time to first oil. Some, but by no means all, contractors focused on engineering are starting to see improved profitability. But the sunk investments made in offshore vessels, jack-ups, and rigs have largely had their equity wiped out in the last few years and this is enabling the offshore industry to compete on price and risk in terms of capital allocation from E&P companies. For as long as that is it’s only, or major, competitive advantage all that beckons is an industry that slowly runs down its capital base until project cost inflation can rise. Something that becomes ever more distant the more competitive shale becomes. I realise it’s a bleak prognosis but there isn’t much else on offer.

Group think and conventional wisdom…

“It will be convenient to have a name for the ideas which are esteemed at any time for their acceptability, and it should be a term that emphasizes this predictability. I shall refer to these ideas henceforth as the conventional wisdom.”

J.K. Galbraith, The Affluent Society

 

“All that we imagine to be factual is already theory: what “we know” of our surroundings is our interpretation of them”

Friedrich Hayek

 

We find broad- based and significant evidence for the anchoring hypothesis; consensus forecasts are biased towards the values of previous months’ data releases, which in some cases results in sizable predictable forecast errors.

Sean D. Campbell and Steven A. Sharpe, Anchoring Bias in Consensus Forecasts and its Effect on Market Prices

Great quote in the $FT yesterday that reveals how hard it has been in the oil and gas industry for professional analysts to read the single biggest influencing factor that is reshaping the supply chain: rising CapEx productivity and its ongoing continued pressure. Money quote:

Mr Malek said that with the notable exception of ExxonMobil, most energy majors had shown they were capable of growing output quickly even when investing less than it used to.

“We all thought production was going to fall off a cliff from Big Oil when they started slashing spending in 2014,” said Mr Malek. “But it hasn’t. The majority of them are coming out on the front foot in terms of production.” [Emphasis added].

#groupthink 

An outlook where E&P companies can substantially reduce CapEx and maintain output is not one in a lot of forecast models. Forecasts are rooted in a liner input/out paradigm that leads to a new peak oil doomsday scenario. But the data is coming in: E&P companies are serious about reducing CapEx long term and especially relative to output, and collectively the analyst community didn’t realise it. The meme was all “when the rebound comes…” as night follows day…

The BP example I showed was not an aberration. For a whole host of practical and institutional reasons it is hard to model something like 40% increase in productivity in capital expenditure. But the productivity of E&P CapEx, along with the marginal investment dollar spend,  has enormous explanatory power and implications for the offshore and onshore supply chain.

Aside from behavioural constraints (partly an availability heuristc and partly an anchoring bias) the core reason analysts are out though is because their models are grounded in history. Analysts have used either a basic regression model, which over time would have shown a very high correlation between Capex and Output Production, or they simply divided production output by CapEx spend historically and rolled it forward. When they built a financial model they assumed these historic relationships, strong up until 2014, worked in the future… But these are linear models: y if the world hasn’t changed. The problem is when x doesn’t = anymore and really we have a multivariate world and that becomes a very different modelling proposition (both because the world has changed and a more challenging modelling assignment). We are in a period of a  structural break with previous eras in offshore oil and gas.

These regressions don’t explain the future so cannot be used for forecasting. No matter how many times you cut it and reshape the data the historical relationship won’t produce a relationship that validly predicts the future. At a operational level at E&P companies this is easier to see: e.g. aggressive tendering, projects bid but not taken forward if they haven’t reached a threshold, the procurement guys wants another 10k a day off the rig. There is a lag delay before it shows up in the models or is accepted as the conventional wisdom.

SLB Forecast.png

Source: Schlumberger

Over the last 10 years, but with an acceleration in the last five, an industrial and energy revolution (and I do not use the term lightly) has taken place in America. To model it would actually be an exponential equation (a really complicated one at that), and even then subject to such output errors that wouldn’t achieve what (most) analysts needed in terms of useful ranges and outputs. But the errors, in statitics the epsilon, is actually where all the good information, the guide to the future, is buried.

But when the past isn’t a good guide to the future, as is clearly the case in the oil and gas market at the moment, understanding what drives forecasts and what they are set up to achieve is ever more important. How predictive are the models really?

A lot of investment has gone into offshore as the market has declined. A lot of it not because people really believe in the industry but because they believe they will make money when the industry reverts to previous price and utilisation levels, a mean reversion investment thesis often driven on the production rationale cited in the quote. Investors such as these have really being buying a derivative to expose themselves, often in a very leveraged way, to a rising oil price, assuming or hoping, frankly at times in the face of overhwelming contrary evidence, that the historic relationship between the oil price and these assets would return.

These investors are exposed to basis risk: when the underlying on which the derivative is based changes its relationship in its interaction with the derivative. These investors thought they were buying assets exposed in a linear fashion to a rising oil price, but actually the structure of the industry has changed and now they just own exposure to an underutilised asset that is imperfectly hedged (and often with a very high cost of carry). Shale has changed the marginal supply curve of the oil industry and the demand curves for oil field services fundamentally. Models utilising prior relationships simply cannot conceptually or logically explain this and certainly offer zero predictive power.

The future I would argue is about the narrative. Linking what people say and actions taken and mapping out how this might affect the future. To create the future and be a part of it you cannot rely on past hisotrical drivers you need to understand the forces driving it. Less certain statistically but paradoxically more likely to be right.

Oil supply shortage? Really?

“We’re able to do, I would say, 40% more per dollar of activity than we did 4 or 5 years ago at $100 oil”

Bob Dudley on BP’s Q2 2018 results.

When you are told there might be a supply shortage you need to understand how much model risk there is in these sort of forecasts. The IEA graph in the header, a variant on the new peak oil theme, being used as the rationale for why a “recovery” for offshore may be just around the corner, doesn’t show the output implications of the cost deflator.

Bob Dudley is saying that BP are getting 1.4x output for each dollar 4-5 years after the “great oil price crash” of 2014. That ~$500bn of expenditure in 2018 buys you what ~$700bn did 4 years ago (roughly what was being produced in 2013?).

This just isn’t consistent with a some sort of “snapback recovery” for offshore that people try and credibly speak of (and that some business models are based). Mean reversion only works as a theory when the underlying mechanics haven’t changed. The offshore supply chain needs to be realistic about the implications of this sort of comment that is clearly being translated into E&P company CapEx plans. Whether the offshore industry believes it or not this is the new narrative and reality in E&P companies and capital is being allocated accordingly.

 

Oil prices, technology, volatility, and productivity…

Oil prices are unusually prone to volatility because both supply and demand are insensitive or “sticky” in responding to price changes in the short term, while storage is limited and costly.

Robert McNally, Rapidan Energy Group

 

Last week Citi’s lead oil analyst came out and said he thought oil prices might dip to $45 per barrel in 2019 and be in the $45-65 per barrel range by the end of 2019. This contrasts with Goldman Sachs ($70-80), Morgan Stanley ($85), and Bernstein ($100). I don’t have a view on the oil price, all this shows you is that intelligent, well-informed analysts, with almost endless resources, can vary in their forecasts by around ~50-100%. Read the whole story to understand how looking at exactly the same data set as all the other equally capable analysts Citi’s analyst reaches such a different conclusion.

What this really shows is model risk: a few percentage points difference in key input variables, even over a short space of time, can have a huge influence over the outcomes. And actually, there are in reality too many influences to model them all accurately: Will there be a supply outage in Libya? What will happen with Iranian oil? What will happen in Venezuela? And these are just a few of the big geopolitical questions alone. You need a forecast for many planning assumptions but in the short-run the oil price is a random walk.

A good example is this graph from the EIA showing the difference between their February prediction of US oil prediction and the current one:

IMG_0717

If you are wondering why your jack-up, rig, or vessel isn’t quite getting the utilisation or day rate you were looking for in that graph may lie the answer? It’s a bold Board that sanctions too many projects in this environment, and in fact the one that is, Exxon Mobil with the huge Guyana finds, is getting slammed by the stock market. Barclays, summing up the “market view” saying:

IMG_0718.JPG

Shale isn’t a swing producer as McNally makes clear, but it does have a much shorter-term impact on the market in way that nothing did prior to 2013. But it also isn’t a given that offshore will have a cost or volume advantage over offshore in 10 years time: companies need to hedge their bets if they are large portfolio corporations. McNally has published ‘Crude Volatility‘ which may make  my summer reading list.

The big area where I agree with Citi/Morse is on technology and productivity.  Morse obviously believes, as I do, that a few percentage points of recovery and technological improvement over the well lifecycle has the potential to radically alter physical oil output assumptions over the long-run. And that is before you get into the wonkish areas such as on what base you forecast the decline volume on.

Against this backdrop is a new wine in the old bottle of peak oil demand: lack of investment and the coming supply shortage. A whole host of energy consulting firms say underinvestment may cause a supply driven price rise: Rystad and Energy Aspects in this WSJ article:

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This despite the fact that gross investment doesn’t reflect the increased volume of supply gained from each incremental dollar at the moment (a point Morse makes), or the fact that oil companies don’t need the same level of reserves now (and investors don’t want them to pay for them).  Woodmac, who in the latest “gotcha” on why shale won’t work (sic), has now discovered shale well rates decline faster than thought… I’ll bet by 2040 the 800k a day production cited in the article is made irrelevant by productivity improvements in extraction and production techniques. But I guess again it shows how senstive large data models are to small input changes (and how desperate research firms are to have some uncertainty and upside to discuss with certain corporate clients where an element of group think appears to be pervading Board thinking).

“Preparing for the Recovery”

Preparing for the future.png Rystad also run’s strategy days for Maersk Supply and numerous other subsea and offshore companies…. “Hang in there guys the recovery is just around the corner when the supply crunch happens…”… (however remember The Dominant Logic is dangerous?)….

Meanwhile the capital deepening in the US shale industry continues apace. Have a look at the new pipelines going in:

IMG_0716.JPG

Once these are built the price discount will disappear, further raising E&P company profitability and some railway carriages and trucks they displace will still exist (‘unit trains’ with 100+ carriages carry >66 000 barrels). Some will be scrapped but the railway carriages are like offshore vessels: high fixed costs and commitments and low marginal costs. That is a short way of saying they will reduce their costs to compete… and the virtuous cycle will continue with the capital base even deeper.

What really matters for offshore at the moment is the competition for marginal investment dollars. Does an E&P company choose to invest onshore or offshore? The big advantages of shale are potential productivity increases and lower upfront cash costs despite a lower margin (i.e. low CapEx high OpEx), this flexibility has a number of distinct advantages in  an era when forecasts are so divergent. It is worth noting that Shell, Exxon Mobile and Chevron all underperformed the stock market last week despite oil prices having risen signficantly over the last year. Shareholders want their money back in an era of uncertainty, not mega-projects that offer future pay-offs.

In an era when the volatility of oil prices is clearly increasing you can be sure that tight oil will be favoured over long cycle production at the margin. The ability to take margin risk over commitment risk is a key part of the investment making decision process.  The graph above shows how volatile oil prices has been, in particular since 2003. It is irrational to go long on fixed commitments in a age of increasing volatility: just as it is illogical to take on a massive mortgage on a rig or vessel in the current market it is illogical to go long on too many 20 year deepwater developments, and the two symptons are obviously related to the same cause. For a baseload of demand that is logical, but that only works for the larger players with significant market share, at the margin assets and projects become harder to finance.

The other issue driving investment towards shale, in a time of capital discipline, is path dependence. Path dependence is a process where each step forward can only be achieved with the prior steps preceeding it. Deepwater followed shallow water as an extension of the skills developed there.

The productivity benefits of shale are such that larger E&P companies must fear if they miss this technology cycle catching up on the “path” may be too hard or expensive given the dependent steps they will have to get there. History matters.

Offshore will remain an important part of the energy mix. But the price rise of the past 12 months has led to only marginal increases in work and a firm commitment from E&P companies to control CapEx in a manner that breaks with the past. Price rises not increases in long term production projects are the short term adjustment mechanism at the moment. In a era of price volatility and extraordinary technical change the future could look a lot like the present.

Relentless shale …

However, there is one area I want to highlight today and that is our progress on capital efficiency. You will recall in 2016, we outlined organic capital expenditure guidance of $13-14 billion per year out to 2021. In February of this year we said 2018 would be $12-13 billion. Today, I feel confident we will be at the lower end of that range.

This progress has created the space for us to invest in this opportunity in the Lower 48, while continuing to hold our organic capital spend at $13-14 billion per year. This is a story of improving capital productivity.

Bernard Looney, CEO Upstream, BP

It was a big week in the shale world last week with BHP selling their shale assets to BP. BP has stated it will divest itself of $5-6bn of assets to help fund this move. What will be really interesting is where the divestments will take place? I expect a further sell off of offshore assets as the overall BP portfolio is weighted further to these sorts of high productivity potential assets. BP made the following comment that they had:

[i]ncreas[ed] offshore top quartile wells from around one-third in 2013 to almost two-thirds this year.

Expect ones outside that category to be classed as “non advantaged” and be up for sale.

The same week the IEA published the graph above showing that for the first time Free Cash Flow from shale will be positive for the first time (see graph above). I never got that worried about this metric because US capital markets have a history of funding loss making companies with high capital needs (Uber being an extreme example) provided there is some sort of rationale and pathway to profitability. But this will only help the “shale narrative” attract further funding.

It is hard to overstate the macro effects of the seismic change in the oil industry but also the world economy, the IMF recently calculated that the shale revolution cut the US current account deficit by 1.4% and on a price weighted basis by 1.75%:

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The shale revolution isn’t just higher prices for the end product: it is a real story of increasing productivity. There is an outstanding story about this on Reuters (appropriately tagged under “Technology” read the whole thing):

Today, BP operates more than 1,000 shale wells that produce mostly natural gas in the Haynesville basin, which straddles eastern Texas, Arkansas and Louisiana.

It has used the data from its automated wells to create a streamlined system that farms out maintenance to a fleet of lower-cost contractors. The firm now orders up repairs much in the same way a homeowner uses a mobile app to hire a maintenance person or a passenger summons an Uber for a ride.

BP puts repair work out for bid to pre-approved contractors, who then compete for jobs. Each contractor is rated after completing the work, and those with high rankings have a better chance of getting hired again.

Welcome to the future of offshore. This focus on process, a hallmark of mass production, has translated into dramatically lower costs:

BP Productivity lower 48.png

This is a genuine productivity improvement and not the result of someone selling a rig or vessel below its true economic cost. At some point the offshore industry is going to have to accept the scale of this industry on its ability to price at the margin and get the utilisation required to make a large number of assets operative.

The shale industry at the moment is one of ever increasing process of capital deepening. This productivity improvement is happening at a time when the rig companies are reporting record rates and utilisation for Super Spec land rigs and associated services. The shale supply chain are managing to increase CapEx and get price inflation while helping their customers lower costs and increase productivity. Yes, there are constraints for take-out in the Permian at the moment, but they will clear in 12-18 months, well before a major offshore project can be completed and a timeframe with enough visibility to make Boards think twice before sanctioning a raft of mega projects.

As these new investments bear fruit, and the capital base has deepened, you can expect to see unit costs lowered even more, particularly where capital replaced labour (i.e. pipeline distribution versus trucking). This is a virtuous cycle. If you don’t think this can happen in commodity industries over the long run look at food production and prices which have followed a similar process of capital deepening and productivity despite demand increasing massively:

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(I am not predicting the end of cyclicality in oil prices merely highlighting that it is not a given that they must increase, particularly in the short-run).

I think this points to the fact that a “recovery” in offshore will be a far more muted and affair than in previous cycles. If anything oil companies are smart enough to realise that competiton is the most time tested method of ensuring competitive prices and the competition for capital allocation between onshore and offshore works to their advantage. It is very hard to see price inflation creep into the supply chain when overcapacity exists in offshore and productivity improvements so achievable in onshore.

Buying time for a managed exit from Deep Sea Supply….

The solution to a debt crisis is rarely more debt and a complete avoidance of the issue. From Solstad:

The Financial Restructuring includes a deferral of scheduled instalments, interests and bareboat payments until December 31st, 2019 in a total amount of approximately USD 48 mill. The Financial Restructuring also entails suspension of the majority of financial covenants in the same period.

As part of the Financial Restructuring, SI-3 will be provided a loan from Sterna Finance Ltd. in the amount of USD 27 million, which shall be applied for general corporate purposes in SI-3.

So the banks stop time and Fredriksen (Sterna Financial) lends the company $27m to get them through the next 18 months? And then what? Day rates rise and solve everything? Where that loan sits in the capital structure will be interesting…

Ships depreciate. That means they are worth less next year than this year ceteris paribus, and therefore their earning power is reduced. This plan is predicated on the fact that this is the bottom of the market and the vessels must work next year. Good luck with that. For the old Deep Sea Supply vessels this is your competition.  Yet in 18 months time they have to earn, after OpEx, $48m just to keep the creditors at bay? It’s just not serious. All the more so because the vessels have an Asian focus and there is widespread agreement that that is the most price-competitive oversupplied region in the world.

All this deal does is keep potential credible supply in the market. The problem for any industry rebalancing is the perceived capital value is so high compared to the actual layup or running costs, and that is an industry wide problem. Pacific Radiance, EMAS, Solship, etc., they can’t all survive at current demand levels, but while they try it is mutually assured destruction.

#lastrollofthedice surely?

Which leads me to believe that all involved know this. Have a look at the bulk of these assets and their status:

SF PSV.pngSF AHTS.png

No lenders really believe they are getting paid all they are owed here surely? My guess is that the JF money has been provided on some sort of “super senior” basis, which gets paid out before the banks, and provides working capital while the next 18 months is spent trying to unwind the Solstad exposure to the DESS fleet. The banks don’t write off anything because it protects their legal position to the claim and preserves the illusion of commitment (and allows the loss to be booked later). A managed wind-down of a clearly not viable business that avoids an immediate firesale would seem the most likely scenario here. A bottle of champagne awaits the first person to send me the IM 🙂