The address that never was…

“Not all barrels are created equally,” she said. “60 per cent of our cash flows are not coming from our upstream business. There shouldn’t be a correlation with our reserves or capital expenditure in upstream. It’s not tied to that.”

Jessica Uhl, CFO Shell

 

Money is not the value for which goods are exchanged, but the value by which they are exchanged.

John Law, Money and Trade (1705)

 

Roughly a year ago this week I gave an address at the OSJ Conference where I was pretty gloomy about the future for offshore. I was invited back this year but unfortunately a change of work circumstances mean it is no longer really the thing for me to do. Having said that I don’t think it is a bad time for a State of the Union speech.

You can guess where this is going…

Last year we had a mini-rally in offshore mid-year. Some of the more outlandish ideas raised more money and invested more capital in an industry already suffering an excess of capital and the share prices of all these public investments are seriously underwater. The banks also continued to pretend things could only get better, when in fact they were clearly getting worse. Solstad and Pacific Radiance are the two most prominent examples of this philosophy but there are a slew more in offshore supply and drilling.

And all the while shale simply grows in scale and scope. I am actually bored now with the really complicated theories about how and why the shale revolution will die. The offshore optimists who touted this theory have been comprehensively wrong in the past and will continue to be so in my opinion.

A few data points show the scale of the infrastructure being used to grow the shale fields:

That folks is your offshore recovery: prices above breakeven at best and lower utilisation as the prices are just high enough to keep zombie companies in business. Welcome to the new normal.

Shale growth may be slowing down,  but it will still grow over 1 million barrels a day in 2019. This slide from Exxon Mobil is reflective of the huge amounts of capital going into Lower 48 production and the continuous productivity immproveents creating the virtuous feedback loop:

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So you can believe some really complicated story about this “offshore recovery” and how it has to happen because reserves are low, or demand will outstrip supply, or shale production isn’t economic, or you can look at what is happening in the US now and accept the logical conclusion: this is the offshore recovery.

Just like the steel industry in the US when it was hit with Asian competition so offshore now has a serious competitor for production investment at the margin. Offshore production isn’t going away but nor is there a boom in store. Projects at the margin are being delayed or cancelled and never coming back. The fleet built for 2014 is still too large by an order of magnitude and operating well below economic break-even. Only a massive increase from the demand fairy can save the current industry structure and that isn’t happening. There are too many boats and rigs with too many operators and this year will bring the start of the slow rationalisation needed. We will end the year with less companies and less tonnage and still the job will remain incomplete.

The most likely scenario at this point is years of oversupply with grindingly poor margins, struggles to get to economic profitability, and a gradual reduction in the fleet as ever so slowly those with less commitment and cash drop out of the race to stay alive. Eventually prices will have to rise to pay for new investment in the offshore supply chain but that looks years away and most firms don’t have the liquidity to wait. Raising new money is getting near impossible for all but the most serious candidates: hedge funds who piled in last year are underwater and look unlikely to wade back in unless the terms are extraordinary, and long-term investors are rightly terrified at the losses the Alternative fraternity have suffered calling the recovery far too early.

The interesting thing is why? In this paper “The elasticity of demand with respect to product failures” by Werner Troesken (pdf) shows that while markets are selection mechanisms they don’t always choose the best products. People continued to buy snake oil in the US long after its efficacy could be argued for.  Maybe the offshore crowd waiting for the boom can comfort themselves with this fact?

However, I see however that in an era of mass production, and rapidly increasing efficiency and unit cost reductions in shale production. To avoid shale, to take your firm off the technological trajectory, would so limit the future  options of a large E&P company that it would not be a wise strategic decision. More marginal capital will be deployed not less. has It is far less risky to invest in a lower margin product like shale, with a shorter payback period, than those custom designed deepwater fields with economic lives vastly in excess of price forecast accuracy.

Worringly for people in offshore is this paper: “Depression babies” by Ulrike Malmendier and Stefan Nagel. If you want to understand how formative experiences can be in lifelong economic actions then this paper demonstrates that investors whose careers were built in recessions invest in fewer equities (i.e. risk capital) even in positive economic times. My rough analogy, which I have no intent to take further, is that E&P execs who lived the 2014 downturn are in no hurry to turn on the CapEx spigot to satisfy all those who tell the world is running out of energy (and as 3 above shows are consistently wrong). And they will be like this forever. Just as those in offshore sit around waiting for the next boom E&P company execs sit around trying to avoid the next investment driven crash.

I have said before loss-aversion theory greatly explains the behaviour of the banks who are crucial to the clean-up of the industry (particularly in Europe and Asia as American losses have been equitized). Every time they have delayed the losses pretending the comeback will happen. And offshore supply in particular was dominated by European and Asian banks. Sooner or later, when the cash flows from the offshore supply and rig asset base cannot make even token payments, and the banks loan books are revealed to be more like Italian regional banks, the real contraction will begin. John Law intimately understood the link between a banks assets and liabilities in a way that would do a modern risk officer proud.

I also mentioned the DSV market last year. I am not mentioning names but building a $150m DSV and selling the vessel for 100k per day for 150 days (at best per annum) is a fools errand in economic terms regardless of the outstanding organisational skills required to deliver it in physical terms. It is simply not possible in a market as competitive as as the Asian DSV market for one firm to outperform others over the long run.

The sale of the Toisa DSVs for between $20-34m shows the economic clearing price of such assets. Such a large gap between actual economic values of operational assets and the historical build costs of new assets can be met by the Chinese taxpayer forever, but eventually the unsustainable nature of this will catch-up with itself. I shall say no more. But Uber can lose money on running taxis for longer than I thought… eventually I will be right here too. Delivering cold Starbucks at $5 won’t keep Uber at a $60bn valuation and IRM work in Malaysia cannot pay for $150m DSVs.

Offshore will continue to be an important part of the energy mix. But the supply chain supporting it to be like that has a great deal of shrinkage to be an economic part of this mix.

The never appearing subsea CapEx boom…

The graph above highlights why comments about the impending offshore capex boom, long prophesied as a certainty by true believers, maybe a long time coming… What the graph shows effectively is that the Energy Select Sector ETF (a proxy for all S&P 500 E&P companies) has significantly underperformed in percentage terms the price increase in WTI (oil) throughout 2018. Not only that the rebased price volatility of oil is high.

E&P shareholders have been saying loudly they want money back from E&P companies not a capex driven option on a future supply shortage. The easiest way for E&P companies to give shareholders comfort at this point, and hopefully boost the share price, is to reduce their forward commitments to long-lived expensive projects (deepwater) and focus on shorter payback projects (shale) to supply volume. From the $FT:

Investors have been pushing executives to cut costs, reign in investments in the type of oil megaprojects that might take decades to pay back, and focus on generating cash, either for dividends or share buybacks. Bernstein Research said this week that companies were responding, noting that those who had raised capital expenditure in the second quarter had been taught a lesson.

“Investors punished E&Ps that raised guidance by 230 basis points on average,” said Bob Brackett at Bernstein.

You read comments all the time about how it is a “certainty” that high oil prices and reserve rundown must, as if some metaphysical law, lead to increased offshore activity. It simply isn’t true. The shareholders don’t want it for a whole host of good reasons: the energy transition, the benefits of higher prices and reduced supply, price volatility when making long commitments etc. This week Equinor reduced CapEx forecasts $1bn for 2019 (from $11bn to $10bn), Total confirmed theirs at the lower limit, and Conoco Phillips did the same. All the E&P companies are making similar noises. You can come up with some really complex reasons for this or just accept the CEO’s are being consistent externally and internally: they are rationing capex reasoning the upside of doing so is better than the downside.

There has been change in perceptions and market sentiment since the last energy rebound in 2008/09:

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If E&P companies are not going to get share price appreciation through sentiment they will have to do it the old fashioned way through dividends and share buy-backs; and cutting back CapEx is the single most important lever they control to do this.

Yes subsea project approvals are increasing (from WoodMac <50m boe):

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But in order for there to a “boom”, one that would influence day rates and utilisation levels across the offshore and subsea asset base, marginal operators have to be able, and willing, to spend and that simply isn’t the case. There is a flight to larger projects, with larger operators, who are ruthless about driving down price. So yes, spend levels are increasing, but check out the size of the absolute decline from the North Sea (from the $FT):

Investments in new North Sea projects have hit £3bn in 2018, the highest level since 2015, after two oil and gas projects received regulatory approval from authorities on Monday…

Capital investments in new North Sea fields were less than £500m in both 2016 and 2017, down from £4.6bn in 2015, but were much higher before the downturn, reaching as much as £17bn in 2011.

£17bn to to less than £500m!!! Seriously… just complete a structural change in the market and the supply chain needs to reduce massively in size and capacity to reflect a drop like that. And a recovery at £3bn is still less than 20% of the 2011 which the fleet delivered (and 30% down on 2015): volumes might be up but the drop in value is just too extreme for anything other than the major players to hold out here. It goes without saying a vastly larger number of businesses are viable with £17bn flowing through the market than £500m. The North Sea might be an extreme example by global levels but it’s illustrative of a worldwide trend.

E&P companies are spending increasing sums on shorter-cycle, potentially lower margin, projects because of the flexibility it offers in uncertain times. Subsea and offshore expenditure and volumes will be up in 2019 but not at the levels to keep some of the more speculative ventures alive.

Permian export capacity, marginal investment, and disintermediation…

“O human race, born to fly upward, wherefore at a little wind dost thou so fall?”
Dante Alighieri, The Divine Comedy

Big news on capital investment in Permian takeout capacity today:  Trafigura Group and Enterprise Product Partners are independently looking to build significant VLCC  export terminals in Houston. The two combined terminals would allow for 2.4m barrels of crude a day to flow out of Houston ports: given that global liquids production is ~100m barrels a day these two terminals allow for around 2.4% of global production to be reallocated through one location.

Permian pipeline capacity is growing by 2m barrels in the next two years. If you were wondering where that oil was going this is one large trading house and one infrastructure provider making their respective moves. This is just a further example of the continued capital deepening in the region that will only further enhance and encourage greater investment in shale-based production.

One cannot help but note the contrast between the Trafigura business model and that of an offshore energy company. Trafigura is providing infrastructure and distribution capability to a whole host of smaller E&P companies that will concentrate on production and require CapEx only to hook-up to a pipeline (or less commonly a rail) network. Trafigura gets (at least) an infrastructure style return on the export facility and full exposure to the commodity price and volume as a trading house (which is what they want). But what it doesn’t have to do is develop a major E&P presence in the basin : in economics/ management speak they have disintermediated the E&P supply chain. It might sound like a dot-com era buzzword but it’s real.

Trafigura has the perfect supplier base of small companies, who wish to sell 100% of output at the marginal (i.e. spot market) price, and are constantly seeking innovative ways to extract that product at the lowest possible cost. In an industry where a host of smaller companies supply rigs and crews to drill wells the expensive coordination costs of this are being farmed out to the smaller companies. Very low barriers to entry, literally $10m per well and full rig crews for only a deposit, will ensure that greater offtake capacity keeps margins capped (at the level required to induce new firms) while Trafigura controls returns that require capital and market power. It is the sort of market and business that locks in structurally higher profits for the infrastructure and distribution arm while pushing CapEx back to E&P companies and their supply chain. If oil prices slump and some of the production companies go bankrupt then their assets will simply attract new buyers at a level that reflects the marginal cost of production and they will still need export and distribution facilities.

This for offshore is where competition for marginal investment dollars resides. A core of finance theory is that returns are linked to risk. You might well be able to get a lower per barrel cost from an offshore field but you have to risk your capital for a significantly longer period of time in an era of very volatile oil prices. Not only that but most offshore developments require that you invest in subsea processing equipment and offtake capability to get to a shared pipeline or increasingly to a FPSO for larger developments. Finance theory also teaches you that all projects that are NPV positive should be funded but the institutional mechanics of raising capital, and the impact of market sentiment on sector investments, mean that isn’t always the case (although really you could just argue that the finance providers have a different view of the risk involved).

Regardless, as the graph at the top of this article shows capital expenditure to offshore projects has declined ~29%!! as a proportion of the total allocation since 2016 (from 41% to 29%) while capital to onshore conventional and shale has grown (IEA) . This is well below the 2000-2010 average and if continued is a large structural industry change. Competition for capital and marginal production is driving this change and there is real competition. There is no ‘inflection point’ for offshore demand, or ‘recovery to prepare for’, without a marked change in this trend. Offshore is losing the battle for capital at the margin and remains competitive only by supplying assets below their economic cost.

Since the downturn in 2014 the holy grail of subsea investment has been to try and find investors willing to buy and lease the infrastructure as opposed to taking E&P risk. The problems with such an idea are legion: the kit is very site and customer specific, has limited residual value, and may struggle to get seniority over the reserves below in the event of a default driven by low oil prices. It is in short very difficult to create something that isn’t simply quasi- equity in the field and surely should be priced at the same level? The ability to genuinely split exploration and production risk from distribution risk, the hallmark of the US midstream system, offers a financing and business model innovation that makes it easier to allow large sums of capital to be raised and further deepen the capital base for production in the region. Finance matters in innovation.

As I keep saying this isn’t the end of offshore but it heralds a new kind of offshore surely? Large deepwater developments allow fully integrated E&P majors to take signficant development complexity, capital, timing, and offtake risk. These companies talk of ‘advantaged oil’ and they have it in these developments. Trading houses with export capability and infrastructure have advantaged oil in their network of production companies who aim to sell 100% of output at the margin, none of whom are large enough to impact the price they pay for the product, but mid sized offshore companies strike me as under real threat and limited in size to the proportion of oil shale/tight oil can supply.

Mid-sized offshore companies do not have the portfolio advantages that large oil companies do. Every development represents a significant fraction of their investment plans and there is a limit to the technical complexity and capital required of projects they can undertake. Previously their ‘advantaged oil’ was access to a resource basin that was needed but did not move the production needle for larger companies. As riskier investments they raised capital on smaller markets (AIM, Oslo OTC, TSX) and used reserves-based financing and bonds along with farmout agreements. But this took time and the higher leverage levels make this risky. The cost of equity, when available, is much higher than in the past because the expectation is that the price of oil will be more volatile. And now the returns are capped by the marginal cost and volumes at which shale companies can supply, which is a new and significant risk factor, particularly in an investment with a multi-year gestation period.

Yet these small-mid sized offshore E&P companies represented the demand at the margin for offshore assets. Large complex drilling campaigns and projects for tier 1 E&P companies always attracted good bids and a relatively efficient price from contractors, but smaller regional projects did not. The margins were higher and the risks greater. On the IRM side these companies negotiated harder on the price but they still had a volume of work that needed to be undertaken. It is these companies, their inability to get finance because of their complete lack of advantaged oil, that are also ensuring now that CapEx (and therefore demand) is not recovering as in previous cycles. These E&P companies are price taking firms with signficant operational leverage/fixed commitments and limited financial or operational flexibility in the short-term. Currently they rely on developments being profitable via the supply chain providing assets below their economic cost. That is not a great strategic position to be in. When there was no competition for your product the story was completely different, but the shale revolution is real.

This chart shows you that demand growth for crude slowed 1% year-on-year for two months and the market became oversupplied (hence the drop in the price of oil recently):

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Investors in oil closely watch volatility indicators like this and as I have said before the logical investment strategy is to invest more secure lower margin companies.

The three major risks to supply listed hy Woodmac at the moment are Venezuela, Libya, and Iran. These are geopolitical risks that could easily end in the short-run. Iran is self-induced and the situation in Venzuela so unsustainable (the real question isn’t why someone tried to assasinate Maduro but why everyone else isn’t?) that it surely cannot last? In prior eras the solution was to build long lasting production capacity in politically stable places. Now surely the solution is to use temporary production capacity where possible and let the price signal take some of the strain?

I think it is axiomatic that offshore cannot boom without a recovery in offshore CapEx spending. At the margin offshore has ceded significant market share in this competition to shale. Major structural change will be needed in the industry before the situation reverses based on current trends.

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.

Demand at the margin…

“We’ve indicated we’re going to keep capital spending flat. We’re in a higher price environment, [but] we haven’t changed our capital budget, and I don’t expect that we will,” Mr Wirth said. “We will not fund every project. We will have projects that meet our economic hurdles, but we’ll choose not to fund, because we’ll have better options.”…

“Frontier-type projects, the riskier investments, are now . . . not as necessary,” he said. “And I think that has implications for everyone.”

For Chevron, that meant every project it invested in would have to be “best in class”, he said. “It can’t just be the kind of project you might have funded historically, because we’ve got better options.” [Emphasis added].

Mike Wirth, CEO, Chevron, Financial Times, July 18, 2018

Image above from Chevron.

Those statements are in essence why the next upswing in offshore will be fundamentally different to the cyclical nature of the industry between 1999 to 2014: in those periods, devoid of shale in a meaningful sense, every offshore project was approved, and the industry built an asset-delivery base accordingly.  As an example Exxon Mobil used to take it’s PSVs and AHTS up to the Arctic in March and wait for the ice to melt so they could start work immediately. That work simply doesn’t exist now. There were a large number of frontier and marginal projects deemed economic that are unlikely to ever be seen that way again (on a risk-weighted basis not just cost per recoverable barrel).

I am a big believer in offshore energy nand believe it will be a significant part of the value chain for a long while to come. The industry is clearly improving from a demand perspective, and if you are a manufacturing or engineering business (for example) then next year will be better than this year. But it isn’t the same for those long on rigs and boats because of the oversupply situation and the fact that the high fixed cost structure makes it hard to reduce costs (i.e. the asset opex is a lot higher than SG&A overhead) in a meaningful sense. The asset based industries face years of structurally lower profitability.

The reason I don’t believe there will be a comeback in offshore demand in terms of the timing and day-rate increases seen in previous cycles is because a significant number of E&P  companies are following the same strategy as Chevron. It is taken as a given in offshore that oil prices and will always come back up, and maybe they will (although the relationship between oil prices and offshore demand has changed), but the optionality of shale has a real value as well for E&P companies and they have fundamentally changed the project approval process. The industry cannot boom on maintenance and decommissioning work, the offshore fleet is so big now it requires a CapEx boom in order to have a cyclical upswing, and there are no signs of that appearing. Project approvals are up but nothing like the levels of of 2013/2014 and it is CapEx projects that will create demand at the margin to meaningfully lift day rates and utilisation levels.

E&P shareholders didn’t see that much of the last boom where high prices were given to the supply chain to expand capacity and you get the feeling they aren’t making the same mistake twice. The offshore supply chain needs to digest the implications that while ‘lower for longer‘ may not have held for oil prices it appears to be an apt description of demand for offshore services.

Shale productivity, oil prices, and marginal demand…

The quote above comes from the CFO of NOV Global, Clay Williams, in 2011. Clearly he understood the transformative nature of shale before many (as well as putting it as eloquently as anything I have ever read). The question for a long time for many was when will shale stop getting funded? But actually the shale revolution is beyond quetion now and the real question for offshore in a era of rising prices again is what proportion of new investment is directed to offshore versus onshore? Particularly for asset owners with high fixed running costs, and rates at below cash break-even on an annualised basis, what is likely in the short-term?

One of the reasons shale continued to be funded wasn’t just rising oil prices it is because capital markets in the US are efficient enough to support business models with high rates of productivity improvement even if the payoff is not immediate. This recent presentation from Helmerich & Payne, the largest US land based driller, shows why:

HP Well efficiency.png

H&P are targeting a 40% increase (as a stretch goal) in efficiency/productivity, an outcome that would further rapidly enhance the economics of shale. Not only that they are doing it with an assumption of pricing power for the drilling contractor where a 20% improvement in efficiency in operations for the customer leads to a 33% increase in their prices (15k-20k), and the next 20% increase brings them another 25% (20k-25k). With these sort of possible productivity improvements, and a much shorter payback time, it is hard to see a freeze in capital funding anytime soon, and in fact at current prices the investment boom is self sustaining anyway. This incremental learning-by-doing and constant improvement is a core part of manufacturing efficiency and has become part of the standard DNA of manufacturing companies (for a fascinating look at how this came to be in the car industry read The Machine that Changed the World). Deming would be proud.

Those sort of productivity improvements, on a per barrel delivered equivalent basis, are the competition for offshore production at the margin for project investment decisions. I continue to believe this will favour much larger, high volume, offshore fields over shallow water developments. Offshore faces the hurdle of clong lead times that were previously just assumed as an unavoidable part of the oil basis. A blog post for another day is the insights behavioural economics offers to this.

Pioneer Natural Resources also came out this week talking up their productivity:

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This data point is interesting and is the crux of future demand across the offshore supply chain:

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That index ratio is really what will drive the strength of any offshore recovery. Since May 16 up until January 18 rising oil prices (much slower than currently) were met with a massive increase in the shale rig count and continued decreasing demand of the offshore rig count. In May 16 the price of WTI was ~$44.00 and Jan 18 the price of WTI ~66.60 so a ~51% increase in the price of oil was followed by a 160% in US land rigs and a 22% reduction in offshore rigs. Any statistical model of industry demand that not have this relationship in the regression is to my mind invalid. Any statistical model without a period break from c. 2014-2016 should similarly be treated with exceptional caution. The future, statistically speaking, will not be like the past.

There are a host of reasons (many covered here previously) but the argument that increasing oil prices will be met at the margin first with an increase in demand for short cycle shale seems irrefutable. Any “offshore recovery” post the shale revolution is clearly going to be very different to recovery cycles prior to this enormous investment and capital deepening process that has taken place in the last 5-7 years.

The bull case for oil… but does it really matter for offshore anyway?

I’m basically an iconoclast by nature and therefore I want to believe things like this:

Burgrabben “Crude Oil: Are you ready for triple digit prices”

And it’s a smart piece of work with loads of really interesting data points. But it is also a variation of “shale can’t possibly work” which I have heard now many times, with a million different reasons, all generally based on shale/tight oil reaching a technical frontier. Subsequently over the years this has been shown to wrong as productivity constantly improves. But if you want the bull case it’s been written for you…

I think it is very hard to believe though that major investors and E&P companies have got this so wrong? A lot of large companies seem to have some fairly explicit forecasts about their production levels and would look very stupid backtracking on the scale some of the shale pessimists seem to think will happen. Surely before the supermajors make major acquisitions they talk to a shale engineer and say “you know like if we buy these wells this will work right?” And maybe more than one and get some opinions? And then some really smart engineers in-house put their names to this? The fact a small number of people seem to think, not for the first time, they have caught out everyone else with something they hadn’t thought of strikes me as a low probability event. I get this goes against everything I say about investment bubbles at times… it’s just this time…

There is also a large section on a “supply gap” with other assets and that maybe true… the market will respond to higher prices just not as quickly as some people hope. I will leave it at that. For the record I have no view on the oil price, in the short run I think it’s a random walk as I always say, and in the long run, the very long run, I believe in technology. But it’s a risky and cyclical business and in a rational world you need a high rate of return to cover for this. Clearly an industry operating at a price level below that of marginal production costs will see a rise in price for a commodity like oil which has an inelastic demand curve.

My major point here is that even if the oil price recovers demand conditions for the offshore industry are extremely unlikely to return to the 2013 type years. Shale only needed to take 5% of global production to drop utilisation rates for offshore assets and change the industry economics over a very short time span. The offshore industry used to need very high utilisation levels and day rates to make the economics work and I find it hard to see a scenario where this will return quickly. Even this report acknowledges the cycle times in offshore and is clear about the increasing role of shale in an absolute sense. The fact remains a larger portion E&P capital expenditure for the next few years is focused on shale/tight oil in an environment where CapEx budgets have been cut. Unless someone can explain to you how they expect a bounce-back in demand that deals with that fact then it isn’t a sensible explanation.

Saipem’s most recent results had a good graphic example of this:

Saipem Q1 2018 backlog.png

Backlog down another 13%… yet Saipem still went long on a USD 275m asset that will keep capacity in the rigid-reel SURF market and force them to lower prices to gain market share. And in fact that asset went to the worst possible competitor for everyone else in the market because Saipem have the resources and technical skills to maximise the value of the Constellation.

Focusing less on the daily change in the spot price of oil and more on the marginal drivers of demand for offshore utilisation would strike me as a better way of gauging industry profitability going forward.