More evidence this is the offshore “recovery”…

I was going to write this anyway today and then looked at the oil price as I was leaving work… down 2.7% at the time of pixel… The graph above comes from the Dallas Fed blog which makes this salient point and helps explain why:

Given current market prices, U.S. shale production will continue growing this year. Indeed, a recent report by the International Energy Agency highlighted that shale production is likely to be a major driver over the next five years. This does not rule out the possibility of major oil price movements, but it does point to a strong tendency that oil prices will be range bound in the near future.

Read the whole thing. Shale has structurally changed the oil industry and fundamentally changed any realistic scenarios for an “offshore recovery”.

Contrast that with the investment boom in shale: If you want to see how the whole ecosystem of companies and innovation are working in a harmony to make US shale more efficient, deepen the capital base, and thereby work in a virtuous circle then this article from the Houston Chronicle that showcases a GEBH project to turn flared gas into power in the region is a great anecdote:

Baker Hughes is using the Permian Basin in West Texas to debut a fleet of new turbines that use excess natural gas from a drilling site to power hydraulic fracturing equipment — reducing flaring, carbon dioxide emissions, people and equipment in remote locations…

Baker Hughes estimates 500 hydraulic fracturing fleets are deployed in shale basins across the United States and Canada. Most of them are powered by trailer-mounted diesel engines. Each fleet consumes more than 7 million gallons of diesel per year, emits an average of 70,000 metric tons of carbon dioxide and require 700,000 tanker truck loads of diesel supplied to remote sites, according to Baker Hughes.

“Electric frack enables the switch from diesel-driven to electrical-driven pumps powered by modular gas turbine generating units,” Simonelli said. “This alleviates several limiting factors for the operator and the pressure pumping company such as diesel truck logistics, excess gas handling, carbon emissions and the reliability of the pressure pumping operation.”

More capital, greater efficiency, and capital deepening. It is a virtuous circle that increases productivity and economic returns and is the signal for firms to invest more. It is a completely different investment dynamic to the one driving offshore projects at the moment.

Shale productivity.png

The above graph from the IEA makess a point I have made any times here: there is no real cost pressure in shale beyond labour (which will drop in the long run). Shale is all about productivity and cost improvement driven by mass production, something the US economy has as an almost intrinsic quality. The cost improvements in offshore are solely the result of over-capitalised assets earning less than their economic rate of return (i.e. oversupply) and is clearly not sustainable in the long run.

That is why firms with a low cost of capital are vacating fields like the North Sea to firms with a higher cost of capital: one requires steady investment and scale, the other investment is a punt on a shortage and price inflation. [A post for another day will be on how on earth some of these larger investors actually get out of the North Sea.]

This IEA data also tells you why this is the offshore reocvery:

IEA 2019 investment mix.png

The IEA is also forecasting overall spending to increase just 6%. So offshore just isn’t getting investment at the margin that will drive fleet utilisation and expansion. In company accounts this is showing up as depreciation significantly outpacing investment and is a constant across the industry. The economics of offshore are such that profitability is dictated by marginal demand (i.e. that one extra day of utilisation at a higher rate) and this graph shows the industry built a fleet for a far higher level and the only realistic prospect here is for structurally lower profitability. Given the high capital costs of the assets this is going to take a long time for the oversupply to work out.

For manufacturers (i.e. subsea trees) the recession is generally over, although not for Weatherford, but if it floats nothing but a wall of oversupply and below economic pricing and therefore sub economic returns is the logical consequence of this industry structure and market dynamic.

The hope of a massive demand boom kept banks from foreclosing and led hedge funds and other alternative capital providers putting money into assets that were (and are) losing cash but seen as “valuable” in the future. Slowly it is becoming apparent there is no credible path to anything other than liquidation for many companies still in business.

Rates will slowly rise, and so will utilisation levels, but only to economic levels i.e. covering their cost of capital in a perfectly competitive market. Absent a demand boom liquidity slowly, and then quickly, vanishes. And that is finally starting to happen now. For example the McDermott 10.25% 2024 bonds, already very expensive, were trading at well below par today implying a 13.5% yield, in effect locking them out of the unsecured credit market completely (and in reality all credit markets). A restructuring beckons. MDR will not be the only one by any stretch. Many rig companies will do a Chap 22 and a wave of supply companies in Europe and Asia are uneconomic and simply cannot survive under realistic financial assumptions.

Slowly the overcapacity in the industry will work its way out to more economically sustainable day rates with higher utilisation levels in a smaller global offshore rig and vessel fleet. But it won’t be a return to 2013, it will be a return to a far lower profitability level despite the smaller fleet, higher prices, and less time and utilisation risk taken smaller companies. There will be a complete wipe-out, almost without exception, of investors who backed offshore “recovery” theses of asset backed companies and an inability of these companies to access funding almost at any price levels. Theories about assets recovering to values implied by book value will be realised for what they are: a fantasy no serious person could believe.

But a far more rational industry and market will emerge. The only thing that could change the dynamic outlined above is a massive demand boom, and the graphs above show you why that isn’t going to happen.

IEA global upstream investment 2019.png

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):

WM Subsea FID.png

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.

Unconventional verus offshore demand at the margin…

Economic growth occurs whenever people take resources and rearrange them in ways that are more valuable. A useful metaphor for production in an economy comes from the kitchen. To create valuable final products, we mix inexpensive ingredients together according to a recipe. The cooking one can do is limited by the supply of ingredients, and most cooking in the economy produces undesirable side effects. If economic growth could be achieved only by doing more and more of the same kind of cooking, we would eventually run out of raw materials and suffer from unacceptable levels of pollution and nuisance. Human history teaches us, however, that economic growth springs from better recipes, not just from more cooking. New recipes generally produce fewer unpleasant side effects and generate more economic value per unit of raw material…

Every generation has perceived the limits to growth that finite resources and undesirable side effects would pose if no new recipes or ideas were discovered. And every generation has underestimated the potential for finding new recipes and ideas. We consistently fail to grasp how many ideas remain to be discovered. The difficulty is the same one we have with compounding. Possibilities do not add up. They multiply.

Paul Romer (Nobel Prize winner in Economics 2018)

Good article in the $FT today on Shell’s attitude to US shale production:

Growing oil and gas production from shale fields will act as a “balance” for deepwater projects, the new head of Royal Dutch Shell’s US business said, as the energy major strives for flexibility in the transition to cleaner fuels. Gretchen Watkins said drilling far beneath oceans in the US Gulf of Mexico, Brazil and Nigeria secured revenues for the longer-term, but tapping shale reserves in the US, Canada and Argentina enabled nimble decision-making.

“The role that [the shale business] plays in Shell’s portfolio is one of being a good balance for deepwater,” Ms Watkins said in her first interview since she joined the Anglo-Dutch major in May…

Shell is allocating between $2bn and $3bn every year to the shale business, which is about 10 per cent of the company’s annual capital expenditure until 2020 and half of its expected spending on deepwater projects. [Emphasis added].

Notice the importance of investing in the energy transition as well. For oil companies this is important and not merely rhetoric. Recycling cash generated from higher margin oil into products that will ensure the survival of the firm longer term even if at a lower return level is currently in vogue for large E&P companies. 5 years ago a large proportion of that shale budget would have gone to offshore, and 100% of the energy transition budget would have gone to upstream.

The graph at the top from Wood MacKenzie is an illustration of this and the corollary to the declining offshore rig numbers I mentioned here. Offshore is an industry in the middle of a period of huge structural change as it’s core users open up a vast new production frontier unimaginable only a short period before. The only certainty associated with this is lower structural profits for the industry than existed ex ante.

Note also the split that the – are making between high CapEx deepwater projects and shale. Shell’s deal yesterday with Noreco was a classic case of getting out of a sizable business squarely in the middle of these: capital-intensive and not scalable (but still a great business). PE style companies will run these assets for cash and seem less concerned about the decom liabilities.

You can also see this play out in terms of generating future supply and the importance of unconventional in this waterfall:

Shale production growth

As you can see from the graph above even under best case assumptions shale is set to take around 45% of new production growth. When the majority of the offshore fleet was being built if you had drawn a graph like this people would have thought you were mad – and you would have been – it just highlights the enormous increase in productivity in shale. All this adds up to a lack of demand momentum for more marginal offshore projects. The E&P companies that are investing, like Noreco, have less scale and resources and a higher cost of capital which will flow through the supply chain in terms of higher margin requirements to get investment approval. This means a smaller quantity of approved projects as higher return requirements means a smaller number of possible projects.

Don’t believe the scare stories about reserves! The market has a way of adjusting (although I am not arguing it is a perfect mechanism!):

Running Out of Oil.png

Common knowledge in offshore and shale…

“With every grant of complete security to one group the insecurity of the rest necessarily increases.”

Friedrich Hayek

Common knowledge is something that we all believe everyone else believes. 

We don’t have to believe it ourselves, and it doesn’t even have to be public knowledge. But whether or not you personally believe something to be true, if you believe that everyone else believes something to be true, then the rational behavior is for you to act AS IF you believe it, too. Or at least that’s the rational behavior if you want to make money.

Common knowledge is rarer than you think, at least for most investment theses. That is, there’s almost always a bear case and a bull case for a stock or a sector or a geography, and god knows there are plenty of forums for bulls and bears to argue their respective cases.

What can change this normal state of affairs … what can create common knowledge out of competing opinions … are the words of a Missionary. In game theory terms, the Missionary is someone who can speak to everyone AND who everyone takes seriously. Or at least each of us believes that everyone else hears the Missionary’s words and takes them seriously.

When a Missionary takes sides in a bull vs. bear argument, then depending on the unexpectedness of the words and the prestige of the Missionary, more or less powerful common knowledge is created. Sometimes the original Missionary’s words are talked down by a competing Missionary, and the common knowledge is dissipated. Often, however, the original Missionary’s words are repeated by other, lesser Missionaries, and the common knowledge is amplified.

When powerful common knowledge is created in favor of either the bull or bear story, then the other side’s story is broken. And broken stories take a looooong time to heal, if they ever do. Again, it’s not that the bulls or the bears on the wrong side of the common knowledge are convinced that they were wrong. It’s not that the bulls or the bears on the wrong side of the common knowledge necessarily believe the Missionary’s statements. But the bulls or the bears on the wrong side of the common knowledge believe that everyone ELSE believes the Missionary’s statements, includingeveryone who used to be on their side. And so the bulls or the bears on the wrong side of the common knowledge get out of their position. They sell if they’re long. They cover if they’re short.

Ben Hunt, Epsilon Theory

Oil and offshore has a lot of missionaries. In cyclical industries separating out industry firm effects from market effects is nigh on impossible. Be on the right side of a bull market and you make enough money to be a missionary respected by the crowd.

I thought of this when I read this extract from Saudi America in the Guardian. I won’t be buying the book (KirkusReviews panned it here) but the parts on Aubrey McLendon of Cheasapeake fame are interesting. However, what is really interesting is that in 2016 when the research for the book was being done there was a strong strain of  the “shale isn’t economic” narrative:

Because so few fracking companies actually make money, the most vital ingredient in fracking isn’t chemicals, but capital, with companies relying on Wall Street’s willingness to fund them. If it weren’t for historically low interest rates, it’s not clear there would even have been a fracking boom at all…

You can make an argument that the Federal Reserve is entirely responsible for the fracking boom,” one private-equity titan told me. That view is echoed by Amir Azar, a fellow at Columbia University’s Center on Global EnergyPolicy…

John Hempton, who runs the Australia-based hedge fund Bronte Capital, recalls having debates with his partner as the boom was just getting going. “The oil and gas are real,” his partner would say. “Yes,” Hempton would respond, “but the economics don’t work.”…

In a report released in the fall of 2016, credit rating agency Moody’s called the corporate casualties “catastrophic”. “When all the data is in, including 2016 bankruptcies, it may very well turn out that this oil and gas industry crisis has created a segment-wide bust of historic proportions,” said David Keisman, a Moody’s senior vice-president.

Many of the offshore “recovery plays” were financed when this was the investment narrative. The “common knowledge” was that there was going to be an offshore recovery, it was simply a case of when not if. The staggering increase in shale productivity was not part of the common knowledge and didn’t form part of the narrative. Go long on assets said the common knowledge… they are cheap… this is a funding issue only… what could go wrong? As the oil price inevitably rose demand for offshore assets would quickly recover right?

As the graph at the top of this article highlights, just as the common knowledge was being formed that allowed a range of offshore companies to raise more capital to get them through to the inevitable recovery, and clearly the demise of shale would occur by simple economics alone, in fact the shale industry was just cranking up.

The results of most of the offshore companies for the supposedly busy summer season show that at best a slight EBITDA positive is the most that can be hoped for. Rig, jack-up, and vessel rates remain extremely depressed and most companies are struggling to even cover interest payments. A few larger SURF contractors are covering their cost of capital but most companies are simply doing more for less. Companies might be covering their cash costs but there is a massive issue still with oversupply, and judging from the comments everyone continues to tender for work they have no hope of getting as everyone is doing more tendering. The cash flow is rapidly approaching for a number of companies and Q2 results have shown the market is unlikely to save them.

The missionaries for the shale industry are currently in the ascendant in creating a new common knowledge. The new common knowledge for offshore will be extremely interesting.

(P.S. If I was the publishers I’d rush the paperback edition of the book out).

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…

IMG_0770

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.

Inflation adjusted WTI price.png

 

Absolute versus relative…. shale and conventional competition at the margin…

conventional-1.jpg

“An uptick of 30% from the abnormally low levels in 2017 might seem encouraging, but E&P players are currently facing a low reserve replacement ratio, on average of less than 10%. This is worrisome considering the impact on global oil supply in long term,” says Espen Erlingsen, Head of Upstream Research at Rystad Energy.

I think this is simply a badly worded comment from Rystad where they mean E&P added less than 10% to overall reserves from  conventional sources. In a relative sense I think Rystad are arguing that reserve replacement has been low (i.e. relative to total reserves). The comment is hard to square with the graphic at the top from the EIA and this comment which makes clear in an absolute sense there is no problem:

In 2017, a group of the world’s largest publicly traded oil and natural gas producers added more hydrocarbons to their resource base than in any year since 2013, according to the annual reports of 83 exploration and production companies. Collectively, these companies added a net 8.2 billion barrels of oil equivalent (BOE) to their proved reserves during 2017, which totaled 277 billion BOE at the end of the year. Exploration and development (E&D) spending in 2017 increased 11% from 2016 levels but remained 47% lower than 2013 levels.

Of the 83 companies, 18 held more than 80% of the 277 billion BOE in proved reserves at the end of 2017. [Emphasis added].

Rystad seem to be measuring “conventional” resources only which in this world strikes me as an irrelevant metric. Shale and Conventional may not be perfect substitutes  (some refineries for instance cannot process light crude in the short-run) but they are close. Either way we don’t appear to be facing an imminent supply shortage caused by under-investment in early stage E&P activity. And in fact the EIA says:

First-quarter 2018 capital expenditures for this set of companies were 16% higher than in first-quarter 2017, suggesting that many of these companies have increased their E&D budgets, which will likely contribute to further organic proved reserves additions in 2018.

Clearly they are measuring two different things, but I still don’t get the Rystad conclusion? The EIA uses proven and economically achievable reserves  on net discoveries and is surely a more relevant metric? Of course it doesn’t support a “Preparing for the Recovery” thesis at all.

If you want a graphic illustration why European offshore companies have been the most exposed to the downturn in offshore CapEx look at the first chart:

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On a rolling three year average investment in Europe, which is predominantly offshore, has dropped to around 30% of previous levels. A far greater proportion than any other region and the reason is obviously that it is a high cost area of marginal production.

You can really see the productivity improvement in the second graph: Capex peaked at over $30 per BOE in 2014 and is heading down for $15 per BOE. The supply chain having gone long on fixed assets hoping to profit from a production boom has just over capitalised and allowed the E&P companies to massively reduce development spend in a downturn.

What the EIA and the Rystad combined show is the profound changes taking place in the production of oil and gas. The data show (partially and indirectly) the marginal investment curves for shale versus offshore/onshore conventional. Rystad show that conventional oil and gas replacement is dropping as a proportion of the energy mix. The EIA data shows the drop in marginal production areas: the huge drop in European CapEx, almost exclusively offshore and extremely expensive on a per BOE equivalent, shows that at the marginal capital is being redeployed in other production techniques.

But what the data emphatically does not show is anything to worry about long-term from a supply perspective.