Overdiscounting… the future of offshore…

The qualities most useful to ourselves are, first of all, superior reasons and understanding, by which we are capable of discerning the remote consequences of all our actions; and, secondly, self-command, by which we are enabled to abstain from present pleasure or to endure present pain in order to obtain a greater pleasure in some future time.

Adam Smith, 1759


For most of these persons are, in fact, largely concerned, not with making superior long-term forecasts of the probable yield of an investment over its whole life, but with foreseeing changes in the conventional basis of valuation a short time ahead of the general public. They are concerned, not with what an investment is really worth to a man who buys it ‘for keeps’, but with what the market will value it at, under the influence of mass psychology, three months or a year hence.

John Maynard Keynes, 1936


The slide above taken from Transocean highlights how competitve offshore has become on a per barrel recovered basis. I’ll ignore the fact that the cost estimates for shale appear high because it isn’t my point: the real point is that to compete in the modern environment offshore oil production will have to be significantly more profitable on a per barrel recoverable basis because there is significant evidence managers underestimate (“overdiscount“) future financial returns the further away they are. Shale returns, while lower, are produced in a much shorter time period than offshore and behavioral finance shows strong evidence that managers prefer these sorts of returns at lower levels when compared to higher returns further away.

In  2011 Andrew Haldane, Executive Director, Financial Stability at the Bank of England, and Richard Davis, and Economist at the Bank of England spoke at a Bank for International Settlements conference and noted:

[r]ecently, in 2011 PriceWaterhouseCoopers conducted a survey of FTSE-100 and 250 executives, the majority of which chose a low return option sooner (£250,000 tomorrow) rather than a high return later (£450,000 in 3 years). This suggested annual discount rates of over 20%. Recently, Matthew Rose, CEO of Burlington Northern Santa Fe (America’s second biggest rail company), expressed frustration at the focus on quarterly earnings when locomotives lasted for 20 years and tracks for 30 to 40 years. Echoes, here, of “quarterly capitalism”.

In 2013 McKinsey & Co and CPPIB surveyed 1000 Board members and found:

  • 63% of respondents said the pressure to generate strong short-term results had increased over the previous five years.
  • 79% felt especially pressured to demonstrate strong financial performance over a period of just two years or less.
  • 44% said they use a time horizon of less than three years in setting strategy.
  • 73% said they should use a time horizon of more than three years.
  • 86% declared that using a longer time horizon to make business decisions would positively affect corporate performance in a number of ways, including strengthening financial returns and increasing innovation.
  • 46% of respondents said that the pressure to deliver strong short-term financial performance stemmed from their boards—they expected their companies to generate greater earnings in the near term.

The implications for offshore investment (decision tree here) versus the certainty of a short payoff from shale investment are obvious. It has been well known in economics for years that managers overdiscount future returns: in behavioural economics it falls under time preference problems. Humans are neurologically wired with a preference for immediacy that affects economic behaviour. As Haldane and Davis make clear:

This evidence – anecdotal, survey, quantitative – is broadly consistent with popular perceptions. Capital market myopia is real.

As early as 1972 Mervyn King, who would later become Governor of the Bank of England, noted that managers in the UK overdiscounted returns from long term investments. This stream of literature dried up as the Efficient Market Hypothesis took over as the vogue theory but it doesn’t change an actual reality.

The fact is that in competition for marginal oil investment dollars there are institutional and behavioural factors pushing for short-term solutions. This article in the Financial Times notes that Shell is under pressure as the CFO hasn’t outlined when the promised $25bn share buyback will start. Do you think the CFO at Shell is pushing for a new Appomattox because it has lower economic costs (but high CapEx) or will she simply seek to favour short pay-off, lower margin, projects?

Managers pushing offshore projects in E&P companies are running into senior managers who represent exactly those type of Board members surveyed by McKinsey and CPPIB. These managers aren’t wilfully myopic, the shareholders are pushing them to be, but they are more focused on immediate payoffs and overdiscounting the costs of the offshore projects. Again this quote from Haldane and Davis seems apposite:

Graham, Harvey and Rajgopal (2005) surveyed 401 executives. They found three striking results. First, managers would reject a positive-NPV project if that lowered earnings below quarterly consensus expectations. Second, over 75% of the sample would give up economic value in order to smooth earnings. Third, managers said that this was driven by the desire to satisfy investors.

When there was no shale this wasn’t an option as the question was “Do you want oil or not?”. The question is a whole lot more complex now and involves and assessment of certainty, risk, payoff potential and timing, and the pricing uncertainty of a volatile commodity over the long run. All this points to the fact the the financial and institutional barriers to new offshore projects are much higher than simple “rational” expectation models of future payoffs would suggest.


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:

Pioneer Improvement.JPG

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

Shale rigs vs offshore.JPG

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.

Data and theory…

Above is the BH rig count ending Friday last week. Look at the change in rig numbers a year ago…

When the facts fit the theory (here and here for example) it might be time to accept the logic?

There is definitely a strong “recovery” in some parts of the oil and gas industry… it’s just in offshore the supply side is stronger than what appears to be a very weak demand side recovery?

Offshore project approvals Q1 2018.png

Source: Ensco.

Bergen… a world leader in fracking advancement… who knew?

From the WaPo today:

Even better, scientists in Norway may have found a good way to store the captured carbon. At a conference in Vienna last summer, a team from the University of Bergen unveiled a promising advance in high-pressure oil and gas extraction. Rather than “fracking” underground rock formations to free trapped fuels, the scientists successfully injected carbon dioxide into core samples to force out trapped oil, leaving the carbon dioxide locked in its place. The new process “increased recoverable oil by an order of magnitude compared with fracking, and at the same time reduced the carbon footprint by associated CO2 storage,” the team summed up.

Fracking has been a game-changer for the U.S. economy, offering cheaper, cleaner fuel and the prospect of energy independence. But this process could be even better, if the Norwegian experiment can be proved in field tests. No more chemically contaminated water, no more fractured rocks and related earthquakes. Furthermore, by creating a lucrative market for large supplies of carbon dioxide, the new technology could drive rapid commercialization of “memzyme” scrubbers.

The full paper is here if anyone is interested.

My only real point with this, without wishing to sound repetitive, is that productivity improvements for shale seem to have significant further potential. Obviously ideas like this take a significant amount of time to come to fruition, but the will, resources, and capital to push the technical frontier for shale are clear. I imagine some tense moments in the bars of Bergen as the University staff explain to the boat owners and crew their idea and its potential implications for an “offshore recovery”…

A supply contraction and rising oil prices…

The comments above are from Schlumberger’s results last week. Note the comments about the only possible sources of short-term supply increase. I think SLB are ignoring increased maintenance spending to bring shut-in wells back but this is probably not a major number.

It is worth noting that this era of rising oil prices, if they remain, is driven by OPEC trying to limit supply to drive the price up for macroeconomic reasons, and is therefore different to the 2008 -2014 increase where the dominant narrative was to increase supply for a booming economy. The narrative counts.

Here is another reason any “recovery”, or boom 5.0, or whatever, in oil prices will be:

Crude Shipments

So any recovery will be just like before only different. Some change will be cyclical and just like the past but some has clearly been secular. Business plans that assume a general “recovery” as being disingenuous.

I ran a very hot half marathon today (Southampton). Anyone who enjoys this blog and feels it has some economic value please make a contribution to the Hospice North Shore (NZ) (an amazing place that took amazing care of my Mum at the end and to whom I am forever in their debt) or the Motor Neurone Disease Association UK.

Thanks in advance.

“This time it’s different…” … But it really is…

I sometimes think the brief downturn of 2008/2009 in oil prices and offshore demand has a lot to do with how the downturn that started in 2014 is interpreted. I was there, got the t-shirt, and it was brutal, but it was short and there was an asset base that was vastly smaller than the current active (or potentially) rig and vessel fleet of today.

The graph above show’s the EIA forecast for US crude oil production by grade (that includes onshore and offshore). Unless you believe this graph to be completely wrong you would have to accept there has been a significant structural change in the industry… as a comparison have a look at the US production levels leading up to the 2008/09 downturn:

US oil production 1986 -2010.jpeg

US domestic oil production was on a downward trend at 5m barrels a day, slowly rising in 2009, before its meteroric 2010 rise. In 2009 the logical dominant narrative, both in investment terms, and operational terms, was that offshore production had to be increased: there was no alternative. Shale was expensive, companies were still thinking oil sands production was a viable technology within current constraints to keep pursuing, and although the investment dip was brutal it was a single season, and the spot price recovered quickly as well.

Now the graph at the top is the dominant logic. There is a self-reinforcing cycle here that is leading investors at the margin to use shale as the swing production method of choice. From 5m barrels a day to 10m and realistic scenarios involve this being 12m. Not only this as a marginal production technology shale is shorter cycle and uses much less initial capex, the trade-off being lower overall profitability. But on a risk-weighted and time-commitment basis it is a far less intensive production technology. As I keep saying here everything Spencer Dale wrote is coming to fruition here over the shale doubters. The force of economics triumphs over engineering constraints of the current technology curve yet again!

Change at the margin it is occurring every day when investment managers at either E&P companies, or fund managers/PE investors, decide to back a shale project over an offshore project. No one is saying offshore is going away, but at the margin the total volume of decisions made one way or the other will dictate what a “recovery” for offshore looks like. There is no doubt this summer will be busier than last summer for work, particularly for IRM where the spending taps have been loosened a little, but the supply situation is such that no one is reporting increased rates it’s all about utilisation.

My point with this, as I constantly stress, isn’t that offshore is going to zero, but that any recovery in offshore is going to look very different to any prior to 1986, because there is now a viable swing producer with a very different commitment profile. Offshore will be part of the energy solution not THE solution, and that is a very different dynamic.

Up until 2010 offshore was the only viable solution so there was a reasonable belief that this was cyclical pause in investment driven by a cash flow issues oil companies were having with the spot oil price. I am just not sure that is a reasonable assumption now?

Frac spread count

The Frac Spread Count is the equivalent of the BH rig count for frac spreads. You can see the tremendous growth in onshore capital equipment utilised that has occurred in a fairly short space of time. This process of capital deepening will not go away, this equipment, which is getting more efficient, will need to be traded even if the price of oil drops. Like vessels it will price at marginal cost if required to keep utilisation high.

And shale appears to be getting ever more efficient:

Now a second revolution is on the horizon as operators prepare to re-enter those wells that launched the first revolution and implement secondary recovery projects. That can consist of operators reinjecting gas into the reservoir to restore pressure and then producing the additional crude and natural gas…

the Permian Basin has been producing for close to 100 years and “we’re not even close to getting all the oil.”

Which led the IEA to issue this graph this morning with the byline “US shale oil growth is set to see the largest sustained rise in history matching the huge expansion seen in Saudi Arabia in the 1960s and 1970s”


And as a topic for another day gas is becoming so cheap that for bulk energy it will take market share off oil eventually. There is growth in offshore as Brazil and the GoM show:

Brazilian production forecast.JPG

There might well be another bull market in oil… but whether it leads to one for rig and vessel companies is altogether a different question? There will be profitable companies in offshore they will be just look, and in some cases be, different from those in 2013/2014.

There is an interesting parallel in shale infratsructure to offshore infratsructure providers in investment terms:

That fate has just arrived for the pipes and plants connected to some of the first great shale-gas plays in Barnett, Woodford and Haynesville. In September, Wells Fargo analysts estimated that four pipelines serving the original boom areas would be re-contracted for much lower volumes. Recurring operating costs and lower prices create distressing leverage on those declines.

According to Wells: “We estimate the four pipelines will see a median tariff decrease of 39 per cent and ebitda [earnings before interest, tax, depreciation and amortisation] decreases of 66 per cent, once legacy contracts expire.”…

This is not the end of the world for the midstream business. Other, better informed sources of capital can replace MLP money. However, the oil and gas infrastructure bubble is over. An American Petroleum Institute study in 2017 estimated “pipeline and gathering capex” would decline from an annual average of $31.3bn in 2013-16 to $20.8bn in 2017-35.

That is still a lot of pipeline but the ongoing returns appear to be weighted in the E&P companies favour, not the infrastructure providers. Offshore investors probably have some sympathy for pipeline owners.

Any offshore reovery scenario needs to be realistic about how the “new demand” will play out on the current and future asset base. Demand will vary by region, asset class, and type of project at the margin, but an overall contraction in the supply side of the market is a certainty as US shale production continues to grow faster than overall oil demand.

Shale productivity and operating costs…

Some interesting data from the Dallas Federal Reserve Dallas Federal Reserve:

Dallas Fed Q2.png

I get the survey methodology isn’t perfect, but it’s a good indication. The trend on cost is interesting, down on 2016 but up on 2017 as cost pressures rise despite productivity improvements.

Look at the required operating costs:

Dallas Fed Q1.png

A slight rise since last year but comfortably below the spot price. The US has shown that financing costs are important, but ultimately given a downturn these producers will find capital provided they can produce above the marginal operating cost per barrel.

Cost pressures are on the rise as capacity constraints become clear. But this is an industry operating comfortably within in its cost and profitability constraints at current price levels.