Winter Is Coming

Note: Whenever a post clearly makes a forecast, I will attempt to frame it specifically and also quantify the likelihood of it occurring. It follows the logic and practice laid out by Philip Tetlock and Dan Gardner in their book Superforecasting: The Art and Science of Prediction, and here on their website where anyone can take part in active forecasting.

The purpose of this is that it means the quality of the forecasts can be judged more objectively by any readers.

In this post I want to highlight and quantify the following prediction that it covers:

  • No major oil company will invest in any new megaproject (greater than $10bn net investment) before Dec 2017. Chance of being correct – 70%
  • Update 12 July 2016 – I was wrong  – but see post Tengiz – A Colossal Bet  for commentary

The End of the $100/bbl Megaproject Era

“Solar is a technology. Costs fall over time and will continue falling. Fossil fuels are, by definition, extractive. Costs tend to rise over time.” Bernstein Research, Asia Strategy 2015, Shouldn’t We All Be Dead By Now?

Recent surveys by the FT and others (see here) have started to question the viability of the large, international integrated oil and gas company (IOC) model as oil prices remain persistently low. “Nightfall” for the industry has been predicted. Its not the first time such a pessimistic assessment has been touted – all previous oil price crashes precipitated the concern.

Specifically, the argument is targeted at the IOC future oil and gas project portfolios, and how their focus on mega-scale project resource developments have fared during the previous high oil price decade. In that era, although well over $1 trillion was invested in large resource developments, the net production growth of all the majors combined was zero, and the majority of the largest projects over-ran cost and schedule budgets substantially. Meantime, the US shale oil and gas firms increased volumes by over 5million barrels per day, increasing productivity per rig by over 30% per annum between 2007 and 2014 to do so.

The argument then questions how the prevailing IOC model can be made to work in a future energy industry that may now move to structurally lower oil (and gas) prices.

More precisely, it suggests the era of synchronized investment by the world’s largest oil firms in large-scale extractive megaprojects as their primary growth model appears to be over. Substantial, ground-breaking projects in the design stage in LNG, gas and oil have been mostly deferred or cancelled in the past year. Those in the execution phase continue to consume capital at high rates, and have almost without exception over-run target budgets by large margins (Gorgon, Wheatstone, Sabine Pass the latest mega-examples).

In a cash-constrained “lower for longer” or even “moderate for longer” world it creates two immediate problems for the world’s largest oil and gas companies: how to maintain project progress but contain cash-flows in the near-term, and more importantly, beyond this, how to develop a plausible growth plan without large projects?

A quote from a Wall St Journal article indicates the nub of the issue:

“For Shell to consider pursuing a new project, it “must be able to break even at $70” a barrel, a spokesman said. A BP PLC spokesman said it uses “a long-term planning price of around $80” a barrel when considering new investments. Exxon Mobil Chief Executive Rex Tillerson recently said in a television interview that the company tests projects “across a range that’s all the way down to $40” when considering projects. A Chevron spokesman said the company has based its “2017 production forecast on a Brent price of $110” and that it conducts a “stress test” of projects at lower price levels.”

It seems like a different world, but the article is dated 8 December 2014. Hence the IOC’s estimate of break-even prices for future projects was then set around and above the $70-80/bbl range.

Given the lifecycle of projects being discussed at that point we can assume that many of the current crop of oil megaprojects in motion or being reviewed still sit economically squarely within this framework.

Now, in Q1 2016 most firms publicly note $50-55/bbl as the new sanction hurdle, and using this latest yardstick over $400bn of projects have been cancelled or postponed in the 15 months since $70-80 was the benchmark. Input costs – labour and equipment – cannot be transformed as quickly to the current price levels: they move to a different set of market conditions and are not as volatile as the oil market (see post Price and Costs). And fiscal and commercial investment policies also take time to be re-adjusted. Hence the only realistic near-term response is to stop all projects that cannot make a viable economic return at the prevailing and forecasted price levels.

The Nightfall argument then concludes by stating that, even with a return to somewhat higher oil prices, the IOCs are looking at increasingly strained break-even levels, and with a moderate pricing scenario their current investment model is not sustainable.

More bluntly. the IOCs may require a long-term $100/bbl oil to resume mega-scale projects.

(Note – when assessing what the industry break-even might actually be, good practice suggests we start with what is called the “base rate” or “outside view” – phrases mostly attributed to the work of psychologist Daniel Kahneman. This merely states when trying to get a handle on what any given project will cost, we should start with what it typically costs in the industry at large.

That is the start point. We can then look at the “inside view” – the assessment of interested parties eg the oil company discussing its own particular project. But we should avoid doing the analysis the other way round in case we get anchored to the insider viewpoint before looking at the wider picture. Lets try to remain objective and look at the actual out-turns as revealed in the general reviews first. In fact, a key contributor to project over-run as noted in the EY review is Optimism Bias – the positive predisposition of insiders (project management, corporate staff and so on) toward their latest project, resulting in the justification as to why it will overcome the problems that besets all the others in the industry. Its not a trivial point – in fact it is a fundamental matter at large in megaproject performance issues.)

If such a price floor – $100/bbl – is not now credible, what then are the options for IOCs to pursue?

Irrespective of what actually happens to the oil price over the next few years, analysts and investors will want to know now what that plan is, and whether it is a primary route forward, or merely a contingency with growth long-term expected from resuming the previous projects.

However IOCs and other important oil firms (National Oil Companies and smaller Independents) choose to address this question, it will change the dynamics and actions within the industry rapidly, as many firms are now forced to pursue different models of growth based on where they are today.

They cannot continue to act as a single cohort and pursue the previous grand consensus of large-scale resource extraction plans.

End of an Era

As major integrated oil companies typically produce about 2-3million barrels per day, and fields decline at around 4-6% per annum, then about 125,000 barrels per day of net new production needs to come on-stream to stand still in output terms. So larger oil firms need to develop relatively large-scale oil-fields to cover the depletion of existing assets, and provide a net contribution to the oil supply requirements of increasing global demand.

There are a whole host of ways to do this: directly via operating assets through squeezing more out of existing fields through to greenfield project development, or investing via acquisition.

In the era of $70-110/bbl oil, the most favoured route to production replacement and expansion was via the exploration and purchase of large scale reserves, and their development via the megaproject model – either as direct operator of the project itself, or an active investing partner. This is because squeezing an operating asset has far less ultimate growth potential.

It was also because of the intersection of two powerful and emotional oil industry narratives:

First, a deep faith within IOCs that their ultimate competitive advantage lay in their project and engineering capability which could efficiently mature even the most complex reservoirs.

And second, that because outside of the Middle East easy oil was no longer available, and oil demand is always growing, the cost of extracting and supplying complex oil reserves would always be met as they would constitute the marginal cost of production.

As oil prices moved strongly upwards from 2000 (despite a sharp but short correction during the 2008-09 financial crisis), these narratives became articles of faith. High oil prices provided increasing cash flows, and escalating hurdle rates encouraged the most complex engineering projects to be regularly approved by various corporate capex committees. The higher the overall cost, complexity, frontier location and innovative nature of the project, the more it confirmed the belief that future oil extraction projects would be at the edge of known logistic, political and engineering capability (and hence only achievable via the IOC skillset), and the increasing oil price reinforced the marginal cost theory.

Megaprojects – typically over $5-10bn in cost estimates and over 5-8 years in development – therefore became the majority fraction of most oil major portfolios. By their nature, even a limited number of these projects quickly dominated investment capex, cashflow and management resources. By the end of 2014 as we saw above, oil firms firmly believed that sanction criteria of up to $110/bbl were a viable way of allocating the majority of company capital.

Neither of the foundation narratives has proven to be true.

First, oil company performance in delivering complex mega-engineering projects has not been an area of sustainable advantage. A plethora of reviews and assessments (see here for an example) on megaproject delivery indicate that across the industry they have almost all run over budget and cost assessments. Numbers vary depending on the study and methodology, but an average blow-out on the large projects seems to sit at around 20-40% increase in schedule and 25-50% on cost.

Reasons vary, but the individualistic nature of these projects (see post Beating Betteridge’s Law for more details) and their structural complexity, resource constraints and limits on learning transfer contributed to high cost and schedule forecasting errors, and no discernible productivity improvements over time. As a result by Q4 2015 most IOC return on capital values were in single digits, impairment levels were running into tens of billions of dollars and cash-flow and incomes were down dramatically with some eg BP posting large losses.

That performance is not about to get better any time soon – in fact it will get worse: the average oil price in Q4 2015 was $48/bbl. In Q1 2016 it is $34/bbl, a further 30% lower. Gas prices show similar weakness. For projects that require something around $100/bbl to achieve lasting economic value this context severely weakens the dominant industry model.

Second, the marginal cost theory was wrong too. Today US onshore shale production produces around 5.5 million bbls per day of oil and gas from about 1 million barrels per day in 2010, or about 7% of the global total. This transforms the Atlantic Basin from a very large importer to a net exporter. These manufacturing methods of oil production are also on average about 50% cheaper than the megaproject extraction route. The marginal theory may have been right in some sense, but it is not being set by the rates of high complexity extraction – its being set by steep supply and demand curves and new ways of manufacturing fossil fuels, tempted by high margins from price spikes.

The resulting price drop since June 2014 has therefore been increasingly labeled structural rather than cyclical.

As we know, predicting the future oil price is a mug’s game. That does not stop us reviewing some range scenarios based on the existing world we are now more knowledgeable about, and reflecting what it may mean specifically for private oil firm project portfolios going forward.

What the world of over $110/bbl made transparent was the actual cost of doing these complex extractive projects – the largesse of the era allowed the full cost of growth via large-scale extraction to find its ultimate break-even point. It suggests that if actual out-turn is added to best internal estimates, then most megaprojects activated in the past 5-6 years actually require close to $90-100/bbl to be robustly economic.

Many firms will talk about new synergies and cost deflation resetting future break-even values, but investors and analysts would do well to be wary.

Whilst some costs may have improved since 2014/2015, they would have to have moved clearly to a new structural efficiency, or else a return to high oil prices would set in motion another spiral of supply chain inflation ratcheting the underlying break-evens up again. What new structural transformative models would have been put in place in the 1-2 years since $90-100/bbl was the actual break-even?

In any event, oil firms may be reluctant to restart megaprojects as it would require remobilizing large teams and equipment that had been let go well ahead of any presumed payback – and with a fragile belief in the long-term nature of the oil price.

In sum, if we discard lower oil price scenarios for now, and instead predict $100/bbl, we can envisage that many oil firms will not react quickly to this new paradigm, preferring to take a cautious approach, pay off debts and dividends and remaining focused on shorter life-cycle and less capital intensive projects.

The fundamental point is this: under both “lower-for-longer ($50/bbl)” and “resurgent-but-cautious ($100/bbl)” worlds, the previous core model of hyper-investment in long-cycle, mega-scale projects looks to be over.

That model, lets recall, cost the industry over a trillion dollars to create no net increase in oil production from the firms that pursued it. It is a production model, that assumes, more or less, a linear link to revenue – more marginal production, at higher cost, equates to higher revenues from higher prices.

The faith in the marginal production cost model has been shaken, and there will be real skepticism for some time on the ability to launch a future majority of capital into frontier mega-scale projects again.

Production or Value? Going ex-Growth

The IEA and others point out at this point that if oil firms do not pursue these vast, high break-even projects, and let net production naturally decline, the price of oil will therefore inexorably increase due to supply-demand imbalances.

It is a strange argument in one sense – urging oil firms to invest heavily in high risk projects to help lower the cost of the product they are aiming to produce. Why not invest more cannily and reap the revenue rewards of higher prices for free? Saudi Arabia is pursuing a production model but it has access to vast and cheap resources: private oil firms are being asked to pursue the same strategy, even as their extraction costs may now be 10 times higher than the Saudi’s can structurally achieve.

The keep-investing-to-keep-production-going argument is also not so straightforward as the end use markets of oil and gas start to differentiate: oil focusing more narrowly on transportation and increasingly influenced by Asian gasoline demand, whilst gas enters a diverse power sector with competition from new energy technologies such as solar and wind, and rapid policy changes from key governments such as China.

For private international firms, with portfolios typically exposed to oil and gas 50/50, it provides significant complexity for strategic decisions.

The overall negative outlook may be correct in the aggregate, but for individual firms a number of choices remain (see also the post – The Depletion Business).

Firms may remain bullish and focus on the long-cycle, organic megaproject as the primary means for growth. Alternatively they can take a bearish assessment, assuming a long period of low oil prices will mean the value of warehousing and investment in large reserves will start to depreciate. This will tend to give priority to leaner projects with quick pay-back and cycle-times, and a more diverse portfolio, including more value chain options eg trading, and, perhaps, even alternative energy.

And, there are multiple points in between.

A Plan for a winter without $100/bbl

Major international oil companies are already reacting by beginning to diversify their investments away from a singular focus on large projects, and even from production growth as a stated target.

Conoco Phillips has signaled its full retreat from deep-water exploration and development, and Chevron, whilst still bullish on the organic mega-project model, has also indicated an increased medium-term focus on its shale portfolio specifically due to its shorter life-cycle.

Exxon-Mobil has stated it will not grow production over the next five years, but has held out for potentially disciplined asset acquisition based on low price scenarios. If none arise, it is prepared for a stoic, disciplined decline. In a more extreme variant, Woodside has set a $35/bbl test criteria for all new projects, and used this almost immediately to exit from the Browse FLNG $40-50bn megaproject and some proposed mergers.

Shell has acquired BG, and will use this scale and market strength to review its new project portfolio – noting that how it sets the criteria for this portfolio restructuring will be critical to its future success.

Total has also indicated it will increase its investment in renewable mega-scale solar projects, in a nod to diversification into alternative technologies – albeit with using less than 5% of its overall capital budget.

The common theme here is increasing diversity of strategy: a reconsideration of production value versus volume as a main strategic aim, and a revision of the method of achieving that aim – with more emphasis given to manufacturing and technology techniques, rather than the major-concept engineering and construction.

As of early 2016, these early reactions can provisionally be summarized as below.


Over the past ten years, the main international players have pursued similar strategies of production growth via large scale extraction techniques – in increasingly complex one-off ventures, with added issues of geographic and political intricacy. In many ways it tries to mimic the NOC model, but at far higher cost. They have now started to move to a variety of other options.

Meanwhilie, the US E&P-plus-Finance oil manufacturing complex that gave rise to the tight oil and shale gas growth is likely to continue on its present course – although M&A and investment activity is likely to be very active in this area.

The era of extraction megaprojects, therefore, as the core strategic development method for the IOCs is now complete.

The IOCs need to follow alternative models – pursuing a focus on value as well as absolute production growth. And adopting technological options to realize significant improvements in productivity and standardization that large-scale extraction concepts were unable to achieve.

A winter is coming – and the major oil firms need to stake out their plans to see it out.