Shale doesn’t have a cash flow issue …and the limits of expansion…

Yesterday the $WSJ had this article on the economics and cash flows of the shale industry. The overall point is logical that if cost increases continue the cost of capital may go up for shale producers and point to it reaching the economic limits of its expansion. I agree with the general thrust of the article in that if the industry isn’t as profitable as forecast the cost of capital will increase, but this comment is being taken out of context by some:

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Of course they didn’t… they are investing for even higher production next year… the comment “within their means” is pejorative and not a reflection of economic reality. That is a sign of confidence from the firms and their financial backers that their output can be sold at a profitable price. The price signal from both the oil and the capital markets is strong.

I also received a comment yesterday with a link to this comment. I don’t think this is a big deal to anyone with a basic understanding of finance because they get this… but then again I have lost count of the number of people who repeat back to me that no one makes money from shale.

I wonder if this isn’t becoming part of the great “Gotcha” narrative that aims to prove that shale isn’t a viable production methodology? Like the CEO of Shell is going to wake up next Tuesday and say “after reading the article in the WSJ we are going to stop investing in shale. Thank goodness I read that or I would never have realised we will never make money from it!” As if those investing literally tens of billions had no idea of the cash flow profile of their assets?

The overall article is interesting only in that it points to what appears to be the current “productive efficiency” of shale, not its demise. The point of the article isn’t that you can’t make money from shale it is that at the margin now it is becoming less profitable and that may affect the pricing of capital. Bear in mind before you read the rest of this post the scale of the increase in absolute oil production shown in the graph above and the amount of capital required to finance this.

For those not versed in accounting cash flow negative might seem like a big deal but it’s not. A casflow statement is made up of Cash From Operations [CFO] (+/-) Cash flows from investing [CFI](+/-) Cash flows from financing [CFF]. It balances with the cash at bank at the start of the period and at the end. Free Cash Flow to the firm is simply the sum of the first two… You would expect the number to be negative in a capital-intensive industry, like shale oil extraction, when you are seeking to grow output volumes significantly, particularly when a number of firms are new entrants into the industry and not financing from retained earnings. You are spending capital to get future revenue and you need to borrow or raise equity to do this. Collectively as all the firms in the industry deepen the capital base for ever higher production they are using more cash than they are generating currently. (I am aware that there are a number of definitions of Free Cash Flow but this appears to be the Factset one and the generally accepted one of FCFF).

If you buy an offshore drilling rig for $1bn and get 100m in operating cash flow for year 1 then your (highly simplified and representative) cash flow statement reads: CFO +100m: CFI -$1bn. That is your “Free Cash Flow” [FCF] is -$900m. It is balanced (all going well) by CFF +900. You own an oil rig that lasts for 20 years but in year 1 you were down $900m in FCF. You can buy as many rigs as you want and be FCF negative (like Seadrill) for as long as you can keep CFF >= CFO+ CFI  i.e. you have access to debt or equity markets. That is all that is happening in shale collectively.

If these were operating cash flow negative then there would be a massive issue. But as this research from the Dallas Federal Reserve (March 2018) makes clear there is no problem with operating cash:

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Or indeed with profitably drilling wells at the current oil price (i.e. including financing):

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For as long as investors believe that in the future the oil price attainable by these E&P companies is sufficient to return capital, and funding markets remain open, then spending more on Operating Income + CapEx combined is no problem. There is rollover risk in the debt but that is a seperate risk and appears to be pretty minimal at the moment.

Pioneer is an embodiment of this: in the first six months of 2018 it generated ~$1.5bn from operations (i.e. selling oil and gas) [CFO], spent ~$1bn on investments (actually nearly $2bn but it sold some stuff as well) [CFI], and then paid back debt of $450m and purchased ~$50m of shares. But some smaller companies who have come in recently will have spent far more on CapEx than they will earn in CFO.

When I have talked about the ‘virtuous cycle’ of capital deepening in prior posts this is part of that network effect of decreasing risks and increasing returns for all involved in the ecosystem. E.g. if Trafigura build an export facility for 2m b/per day it lowers the risk for every E&P company (and their financiers) that they can sell more oil profitably. So more investment comes into the sector in an ever-expanding circle, lower costs, replacing labour with capital. That is what appears to be happening here. The limits of this process are there and are hinted at in the WSJ:

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Permian production will be up 19-24% according to Pioneer so it’s not all bad. Costs are increasing as the Permian reaches the constraints of labour and capital as has been well documented. Some of these will disappear with new pipelines and other capital deepening, e.g. a replacement of capital over labour as excess surplus is currently trucked or railed out, but some will continue given the huge increase in absolute production volumes. It is no surprise that with such a huge percentage increase in production that at the margin each incremental barrel becomes more expensive in the short-run, but then the capital deepening effect will kick in and the long-run cost curve will decline, as always in mass-production, and then the unit costs drop again… ad infinitum

Pioneer are saying with that statement is that their marginal output on capital is declining slightly this year as cost increases have not kept pace with productivity improvements. That isn’t surprising because the sheer volume of output increased has consistently surprised on the upside. If the project costs increase 10% and this isn’t covered with higher prices and/or productivity improvements then investors will change their price of capital to reflect diminished expectations.

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But this production capacity isn’t going away. The rigs have been built. The pipelines have been, or are being, built; the same goes for export terminals etc. The capital base of the industry has increased massively and is facing some teething problems. But in a little 4 over years the US tight oil industry has driven US production up to over 11m b/ per day in 2018, over 6m b/ per day of that from shale up from ~4m b/ per day in 2017.

What should really worry those in the offshore community is that this is an industry that increased production 50% in a calendar year before hitting the limits of economic growth, and it did this while increasing productivity and lowering unit costs. Someone isn’t waking up next Tuesday and realising it has all been a massive mistake and turning the tap of funding or production off. The US shale industry is a deep and entrenched part of the energy mix now. Current forecasts might be out by a few hundred thousand barrels a day but they are not going to be out by millions. This production is real and permanent with profound implications.

The core logic of the WSJ article is surely right: A rise in the costs of shale relative to output signals the limit of the economic efficiency and therefore the diminishing returns to capital may make it more expensive for shale E&P firms to fund new projects. Shale and offshore compete for E&P company CapEx and if the cost of funding shale projects rises (on a productivity measured basis) that should increase relative demand for offshore as a substitute. But the Free Cash Flow from an offshore project is massively negative in the short-run and over time has higher yields, whereas the reduced CapEx commitment, despite its lower margin, is one of the chief attractions of shale. Cash for investment is not the issue.

I think it sits uncomfortably with forecasters who claim that day rates for jack-ups will double within two years, or other such notions, and it does not seem to be incorporated in the strategic planning assumptions of a large number of offshore companies or investors where the logical outcomes of such data sit uncomfortably. The offshore industry built a fleet to handle 2013 demand when shale was producing ~2.5m barrels a day, it is now producing 6m and is growing faster than the overall oil market growth and forecast to do so until 2021 at least.

Hard strategic questions arise for the offshore industry: how do we compete in an industry which faces potentially declining market share for our underlying product at the margin? How do we compete in an industry when a competitor with a different business model has taken 10% of global market share in the space of 5 years and we buy 25 year assets funded on short-term contracts? What level of asset base shrinkage does the offshore industry require to be competitive? How many firms will have to liquidate given this necessary shrinkage? What will the surviving firms look like? How much can they realistically expect to make? What are our assets worth?

There are a lot more questions based around this logic. But if you are simply expecting a day-rate increase and a demand side boom based on shale magically running out of cash at some future point I think you are going to be very disappointed.

Capital reallocation and oil prices…

The above graph comes from Ocean Rig in their latest results where despite coming in with numbers well below expectations they are doing a lot of tendering. At the same time ICIS published this chart…

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It is my (strongly held) view that these two data points are in fact correlated.

I saw an offshore company this week post a link to the oil price as if this was proof they had a viable business model. Despite the rise in the oil price in the last year there has been only a marginal improvement in conditions for most companies with offshore asset exposure.  There is sufficient evidence around now that the shape and level of the demand curve for offshore services, particularly at the margin, is in fact determined by the marginal rate of substitution of shale for offshore by E&P companies. That is a very different demand curve to one that moved almost in perfect correlation to the oil price in past periods.

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Source: BH Rig Count, IEA Oil Price, TT

This week two large transactions took place in the pipeline space. The commonality in both is new money comping into pipeline assets that E&P companies own. Over time the E&P companies hope they make more money producing oil than transporting it. But they have found some investors who for a lower rate of return are happy just carrying the stuff. More capital is raised and the cycle continues. On Friday as well Exxon Mobil was confirmed as the anchor customer for a new $2bn Permian Highway pipe. These are serious amounts of capital with the Apache and Oxy deals alone valued combined at over $6bn and shale producers confirming they are raising Capex.

When I people talk of an offshore “recovery” as a certainty I often wonder what they mean and what they think will happen to shale in the US? There strike me as only three outcomes:

  1. At some point everyone realises that shale technology doesn’t work in an economic sense and that this investment boom has all been a tremendous waste of money. Everyone stops investing in shale and goes back to using offshore projects as the new source of supply. I regard this as unlikely in the extreme.
  2. Technology in shale extraction reaches a peak and unit costs struggle to drop below current levels. In particular sand and water as inputs (which are not subject to dramatic productivity improvements but are a major cost) rise in cost terms and lower overall profitability at marginal levels of production. This would lead to a gradual reduction in investment as a proportion of total E&P CapEx and a rebalancing to offshore. Possible.
  3. Capital deepening and investment combined with technology improvements cause a virtuous cycle in which per unit costs are reduced consistently over many years. Such a scenario, and one I think is by far the most likely, would place consistent deflationary pressure on the production price of oil and would lead to shale expanding market share and taking a larger absolute share of E&P CapEx budgets on a global basis. This process has been the hallmark of the US mass production economy and has been repliacted in many industries from automobiles to semiconductors. Offshore would still be competitive but would be under constant deflationary pressure and given the long life of the assets and the supply demand balance would gradually converge at a “normal” profit level where the cost of capital was covered by profits.

I don’t know what the upper limit of shale expansion in terms of production capacity. I guess we are there or near-abouts there at the moment, but I also don’t really see what will make it stop apart from the limits or organizational ability and manpower?

It is worth noting that a lot of shale has been sold for significantly less than the highly visible WTI price (delivery Midland  not Cushing):

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And Bakken production is at a record:

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Each area creates its own little ecosystem which deepens the capital base and either lowers the unit costs or takes in used marginal capital (i.e. depreciated rigs) and works them to death. The infrastructure created by the temporary move away from the Permian may just create other marginal areas of production.

I think “the recovery”, defined here as offshore taking production and CapEx share off shale, looks something like this model from HSBC:

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I suspect it’s about 2021 under this scenario that the price signal starts kicking in to E&P companies that at the margin there are more attractive investment opportunities to hit the green light on. That’s a long way off and is completely dependent on some stability in the market until then, but under a fixed set of assumptions seems reasonable. Note however the continued growth of shale which must take potential volume from offshore at the margin.

The offshore industry needs to get to grips with the challenges this presents (I have some more posts on this on the Shale tag). Mass production is deflationary, indeed that is it’s purpose. Shale is deflationary in the sense of adding supply to the world market but also deflationary in terms of consistently lowering unit costs via improving the efficiency of the extraction process and the technology. Offshore was competitive because it opened up a vast new source of supply, but it has not been deflationary on a cost basis (until the crash caused its assets to be offered at below their economic cost).

I’ve used this graph before (it comes from this great article) it highlights that the 1980s and 1990s had generally deflationary oil prices based on tight-monetary policy and weaker economic growth expectations. Ex-Asia the second part of that equation is a given today and US$ strength means oils isn’t cheap in developing countries. As the last couple of weeks have reminded us there is no natural law that requires the oil price to be in a constant upward trajectory.

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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.

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:

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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:

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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:

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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:

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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.

The scale of shale…

Exxon Mobil signed a JV on Tuesday with Plains All American Pipeline LP to build a pipeline that will ease it’s offtake problems in the Permian. Permian has been trading at a discount to WTI of up to USD 27 per barrel due to export constraints from the region so there is a real incentive to come up with a permanent solution.

The thing that struck me was the scale of the pipeline: 1 million barrels capacity per day. That single pipeline will carry as much as the entire output of the UKCS! ~1% of global oil demand being carried in one pipeline. There are a lot more of these pipelines being built as well and they are constructed relatively cheaply and very quickly.

I repeat again that I really struggle to see how a multi-year boom in oil prices can happen now on the same scale as previous cycles. The ability of shale to act as a marginal producer and the ability of E&P companies to develop the infratsructure much more quickly than before seem to act as cap on the price that hasn’t existed before. They could be famous last words but the scale of the investments and infrastructure being committed to Lower 48 counts is part of a genuine supply side revolution in the current oil market.

Shale and offshore… the competition for marginal investment dollars…

Last week the Baker Hughes rig count for the US came in and again it was up. In the graph above Woodmac are highlighting it that Lower 48 US shale production may crack 12m barrels a day.  As recently as 2013, when offshore was starting to go really long on ships, US shale production was ~3.0m per day. It has in short been an industrial phenomena, one as I have noted here before no other economy in  the world could have marshalled as it has required enrmous flexibility in capital markets and the ability to turn a service industry into a manufacturing process.

The narrative has changed as well. Shale has consistently outperformed even optmistic forecasts:

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As recently as 2016 even BP’s renowned research team were only predicting a fraction of actual demand. Shale now represents an enormous portion of workd output and it’s economic model of short-cycle low-margin is the antithesis offshore but this flexibility around spending commitment is clearly very valuable to E&P companies in an era of price volatility.

So I get as the price declined in 2014/15 you could maybe make a reasonable case for a quick rebound in offshore? 2016 at a stretch, although I think the market signals for offshore were already clear byt then, but I have to say it strikes me as hard now for people ignore the scale of this change and to argue there will be some demand driven boom coming in offshore. E&P companies have stated repeatedly they are sticking to forecast offshore CapEx numbers and they seem to be sticking this.

I still think there are too many business plans floating around which have as a core assumption. This from Ocean Rig:

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“[F]or the market upturn” (emphasis added)… like it’s a given? I get it’s off a low base but I think we all know when people talk about that sort of recovery they mean a deep cyclical one that flows to rig and vessel operators who will make a ton of money.

But let’s look at the scale in terms of shift at the margin in incremental output:

Long term offshore.png

The last time the oil price dropped and offshore boomed back,whichever cycle you were talking about but especially the quick 2008/09 rebound, that yellow portion of incremental investmnent simply didn’t exist on the graph in a meaningful sense (and since this graph was done shale is more important). A business plan that simply ignores this reality an insists on a change in market conditions as it’s defining principal is simply logically inconsistent to my mind. Clearly offshore is an important part of the energy mix going forward, but in 2009 it was really the only alternative to traditional onshore production and that clearly isn’t the case now.

Offshore used to have very high utilisation rates, that is what made small companies in an extremely capital intensive industry viable, but it is clear that the scale of investment in shale is having a profound impact on utilisation levels and this is changing the entire economic structure of the industry. This point is a prelude to a further few posts that have this logic as there core.