Capping the price of oil… The Visible Hand of US managerialism…

It is impossible to understand where I am coming from on this blog it without grasping the implications of the graph above (also used here). The graph from the Federal Reserve Bank of Dallas earlier this year highlights the level at which it is profitable for E&P companies to drill new wells. Clearly this is well below the current oil price. The price signal is strong: drill more wells.

Shale oil production is not resource constrained. There is no shortage of rocks to frac or sand to feed the beast. Pioneer estimate there is in excess of 250 years supply in the Permian basin alone at significantly higher production rates than today. There might be a shortage of rocks to frac at an economically efficient price but that answers a different question. The limiting factor on shale is not resource availability but the technical and organisational constraints associated with its growth. The constraints shale faces in the US are organisational: raising capital, training people, building pipelines and new rigs, all the challenges of maximising a known process. Over time no economy in the world is more adept at solving these challenges than the US economy. Chandler called it The Visible Hand and he was right.

This is a massive change from the recent era of offshore domination. Shale is a mass production process where unit costs are constantly being driven down. Offshore was a custom process: each field development was a one-off, each rig and vessel (largely) were one-off’s, each tender was a one-off. The whole chain was geared to custom solutions and while it was efficient at high volumes it is not a deflationary process. The Brazilian pre-salt finds while enormous in size led to a cost explosion throughout the industry and not one it has fully recovered from. The Harsh Environment UDW rigs while significantly more capable than jack-ups did not reduce per barrel costs they just helped us access a scarce resource that we didn’t think we could get from anywhere else. We were happy to pay the price.

It is a very different world now. It is all well and good for the $FT to claim “Shell hails bounceback towards deepwater drilling” but the story carries a more modest message:

“Deepwater can compete if not demonstrate higher returns because of fundamental cost reduction,” he said. “Break-even prices in deepwater — we are now talking $30 per barrel.”…

“It’s great to have both in the portfolio and we are growing our shales business . . . but in terms of sheer cash flow delivery our deepwater has significantly more cash flow potential,” said Mr Brown.

We are into deepwater at $30 a barrel Shell are saying, but we like the competitive tension of shale and we will keep our options open. The upside is in other words capped.

I think the price of oil is therefore capped in the long-run, and I stress that because an industry run with minimal stocks and a highly interconnected supply chain is always going to have short-run volatility, at the rate at which the US shale industry can organise and finance itself and supply marginal production. Eventually the oil price will be capped at what these producers can profitably supply to the market because over time they will continue to grow production significantly. This is an industry with very low barriers to entry and a wealth of subcontractors who can supply kit, and while the offshore rig count has had a fairly minimal improvement globally over the last year there is an almost .9 correlation to the oil price and the US land rig count:

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There is a good article here as well about how in the long-run refineries can process various types of sweet/sour and light/heavy. Again there will be a short-run transition for some refineries who cannot handle light sweet crude but the processes are known and it is simply a cost-optmisation exercise between cheaper light-sweet crude versus more expensive heavy-Brent (for example).

This is clearly a long transition but it strikes me as an inevitable one. US shale production will over time increase as the capital intensity and investment deepens. The huge capital and organisational requirements this will entail ensures this is not an overnight process, but it is a continuous process and one where the inertia now seems unstoppable. This is why I strongly believe that the offshore industry demand curve has lost its correlation with the oil price and a far more complex demand line needs to be plotted for companies.

Offshore’s golden age post 2000 simply didn’t have this competitive supply source, and certainly not one with a major deflationary bias, to compete with. Every strong recovery in global demand led to a straight linear investment in offshore as the only marginal source of supply… ‘there is no easy oil’ people used to say as cost inflation took hold of the offshore industry. But now there is and not only that it appears to be getting cheaper to access it as well.

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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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.

 

What gets measured gets managed…

Chevron and BP released data this week highlighting their continuing focus on reducing production costs and productivity improvements. To set the tone in their Annual Report for 2017 for BP made this comment to the above graph:

Dated Brent crude oil prices averaged $54.19 per barrel in 2017 – the first annual increase since 2012 but roughly half the average of over $110 seen in 2011-13.

Which just goes to show that while the offshore industry is using an oil price USD 60-70 to show increasing confidence it may not feel like that to an E&P company who spent billions on projects with significantly higher price assumptions a few years ago:

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This Chevron slide highlights why the Demand Fairy hasn’t appeared in  offshore despite a rise in prices:

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Spending on Subsea at Cheron is down nearly 70% since 2014! This is an absolute number so the fact that Chevron have completed some major projects influences this, but it also doesn’t change the fact of the scale downwards in subsea spending that a ‘Super Major’ has managed to make in a very short space of time. That drop in production costs comes solely from doing stuff internally cheaper but in reality by procuring from the supply chain at ever cheaper rates.

BP has also dropped its production costs significantly:

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The blue “REM” by the way means the remuneration committee looks at this before allocating senior manager pay. In other words senior managers have a great deal of economic interest in ensuring this gets lowered constantly, as the dictum goes “what gets measured gets managed”. Interestingly in 2013 this wasn’t a metric, then it was all about operating cash flow and delivering production targets and projects. Now saving a few thousand a day on a rig or vessel, going offshore for less days, doing more work onshore if possible, all these will be looked at with a degree of rigour unknown in past times. This is a new and constant trend in the offshore industry and I doubt it will ever go away now.

The continuing impact of this for those involved in offshore is clear: there will be a relentless focus, despite an easing of spend for offshore, on driving costs down. These targets will be filtered down the organisation through objectives and goals to other managers who will be bonused against cost reductions. Pushing the supply chain to lower costs will be measured and therefore managed: the clear implication in a period of oversupply is continuing margin pressure.

The argument that offshore spending will have to increase as the Reserve Replacement Ratio is dropping is starting to look tenditious as well:

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Clearly it’s all about the shale at Chevron, but BP was fine as well:

BP RRR 2017

Chevron is making clear where future investment will go:

  1. Deepwater US

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2) Shale in the Permian (note the comments re: “factory” something I have discussed here before)

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While BP is also making clear that offshore is important but will only be part of its investment in projects:

BP project mix 2021

Two companies doesn’t make an industry, but these were, and remain, significant investors in the offshore space. But it is clear they have changed in a structural way how much they will invest in offshore, and how the invest in offshore, and the amounts are significant to the offshore industry supply chain as a whole (especially as they don’t seem to be anomolies).

When I look at data like this,l and see business plans that rely solely on an “inflection point” in demand, or waiting it out for “the recovery”, I don’t think they are reflecting likely scenarios now. A base case for offshore is surely one without a dramatic change in demand conditions? The implications for many business models in the offshore space from that are profound nearly four years after the price decline began.