Profile view

One of the most damning things about the state of the oil industry is how this downturn – which has sent oil to between $40-$50 per barrel – has caused the whole industry to freeze like a rabbit in the headlights.  As I have said before:

We last saw $50 per barrel oil in late 2004, before which it had been consistently lower than that.  I was working in the industry in late 2004 and I don’t recall there being mass panic among the oil companies about not being able to cope.  So what’s different this time?

The strategy – if it can be called that – of the major players in the oil industry seems to be one of “hold fast until the price picks up again”.  Most are “cutting costs” by not continuing with ongoing or potential developments, and then boasting about how they’ve steadied the ship.  This would be like Toyota cutting costs by putting a hiatus on car production for a while: all they’re doing is clobbering their future revenue streams.  It’s not as if the projects they are cancelling can be resurrected and brought on stream immediately the oil price rises; these projects take years to develop, so if they’re going to wait until oil is at $80-$100 per barrel before FID, it’s going to be 3-5 years down the line before you see any revenues by which time the oil price might have gone back down again.  The lack of leadership, or even basic imagination, is staggering.  Little wonder the sharks are circling from the anti-carbon lobby when they see such weakness on display by the supposed captains of the oil industry.

The oil companies have been maintaining this holding pattern for over a year now, with no sign of it ending.  If they are not careful, they will find smaller, nimbler companies have figured out a way of developing fields and making money at $50 per barrel.  We’re not there yet, but I think another year of this and we’ll see projects going ahead which the big players wouldn’t have thought possible.

The lack of strategy among certain players was apparent when they flipped the script completely as the oil price took a nose dive.  In other words, their entire strategy – one of maximising production regardless of costs – was utterly dependent on the oil price staying above $100 per barrel.  As soon as it tanked, the strategy changed.  This, dear readers, is not a company strategy.  Now everyone is talking about reducing CAPEX, but nobody has any idea how to do it.  Now I’m just a lowly cog in the belly of the great oil and gas machine, but I have worked on enough projects to see why they are so damned expensive.

Below is a graph showing what is called an oil production profile, showing the rate at which oil is produced against time for any given field.

I post this just to get any layman familiar with the concept.  Basically, the production rate of an oilfield quickly ramps up to a plateau, which is achieved by drilling more wells and bringing them on stream, and the plateau is maintained for as long as possible until the reservoir depletes and the production rate declines.

In reality, the situation is a little more complex, and we must consider also the rate of produced water.  When oil is extracted from a reservoir, it brings with it “associated gas” and “produced water”, both of which must be treated and handled (flaring the first and dumping the second in a nearby river is somewhat of a no-no in the modern industry).  I’m going to ignore the associated gas in this post, and concentrate on the oil and produced water.  In a real field situation, the production profile will look something like this (click on the picture to expand):

As you can see, the oil production looks good between 1970 and 1981, and then you hit a crossover point where you’re actually producing more water than oil.  From that point onwards, the oil production rate declines as the produced water increases until you’re producing a dribble of oil and a colossal amount of water.  In the above example, this isn’t much of a problem: the operators have had a good 10-12 years of steady production between 50k and 80k barrels per day, which would more than pay for the CAPEX of the facility in the first couple of years.

The economics of potential oil developments are judged in today’s industry largely on how quickly the CAPEX of the facilities, pipelines, etc. can be recovered.  With oil sailing along merrily at $100-$120 per barrel, oil companies and their permanently cash-hungry governmental partners favoured production profiles like the one below, which allowed them to collect as much cash as possible early on:

This is fine if CAPEX is not an issue, but as anyone who’s worked on the engineering of a facility with a production profile like the one above could tell you, the facilities get expensive very, very quickly.  For a start, most major projects these days are offshore, either on fixed installations or floaters.  That means size and weight is a serious constraint, and costs can accumulate very quickly.  As the above chart shows, your facility must be designed to handle 180k barrels per day of oil production: that means huge separators, inlet manifolds, power requirements, gas treatment, flare header, knock-out drum, flare stack, flare tip, etc. But you’re only using that capacity for 4-5 years before your production rate declines, so all that large, heavy equipment you’ve spend billions on is now under-utilised for the remaining 20 years of the development.  But note, due to the increased water cut later on in the profile, you also need produced water treatment equipment that can handle around 140k barrels of water per day, and this equipment is large, heavy, and expensive.  In short, opting for a production profile which maximises production in the first few years increases the size and weight of the equipment and facility considerably, and with it the CAPEX.  In the main, is is only these production profiles which the stakeholders of major projects have approved in the recent past.

The problem now that oil is at $40-$50 per barrel is CAPEX has become a cause for concern.  In the drive to minimise CAPEX, engineering contractors are being leaned on to cut corners, optimise equipment selection, bend safety rules (yes, really) and take a look at their own salaries (the generous packages of oil company employees are not up for consideration, of course).  But what has yet to happen is an oil company executive approve a production profile like the one below:

The production profile in the chart above is much flatter, and once plateau is reached it ticks along for 20 years at much the same rate, albeit much reduced from the plateau of Profile 1.  Your main process equipment need only be designed for 110kbpd of oil and 130kbpd of produced water, and this equipment will be well utilised for the entirety of the development.  This would bring the size, weight, and CAPEX of the facility down considerably, but stakeholders would have to wait longer to recoup the CAPEX and would not turn the project into a cash-cow until much later.  Which I expect is why these profiles don’t get approved very often.  Profile 2 also has another potential advantage over Profile 1: it is not as prone to fluctuations in the oil price.  Profile 1 is great if oil is at $100+ between 2011 and 2015, but not so great if 2011 sees the oil price plummet to $50 and not pick up again until 2017, just as production goes into decline.  What with these projects taking 5-8 years to get into production and oil company executives still reeling from the shock of the oil price collapse 18 months ago, I’d not be too confident of their ability to predict that this narrow window of opportunity will coincide with bumper prices.  Profile 2 is much less dependent on the oil price, and over the course of the development one would expect things would finish up about even having seen both a boom and a bust.

(Note: the two profiles I have shown above might not be strictly realistic, and I am sure a reservoir engineer or production geologist could point out a few faults with either graph.  But they serve to illustrate the concept, i.e. higher production rates = higher CAPEX.)

I have always been of the opinion that major oil companies should seek to have in their portfolio of developments a solid base of small-to-medium sized projects with profiles similar to that of Profile 2, a handful of large projects with profiles similar to Profile 1, and some number in between such that their exposure to an oil price collapse and a squeeze on CAPEX is limited.  But the mantra up until 2014 was that mega-projects were the future of the oil business, particularly those in harsh environments and/or deep water, which require tens of billions of dollars in CAPEX.  Only now that these projects are no longer being approved, we don’t see smaller, less risky project being approved either.  Now it might be that oil company executives insist on recouping CAPEX as quickly as possible in unstable, unpredictable places such as Nigeria and Russia and so are reluctant to expose their investments over longer time periods, and that would be reasonable enough.  But I suspect the reasons are different, and I speculated about this before.

The oil industry is now run by a generation of people who have gotten fat and lazy on bumper oil prices, and have forgotten how to make tough decisions and work with low oil prices.  The industry executives don’t know how to analyse an economic model which doesn’t fit with their modus operandi of the past 10 years, and the development, engineering, and project management divisions don’t know how to do a project cheaply any more.  The lower oil prices have dealt them a square kick in the bollocks, and they don’t know how to deal with it.  I reckon they have about 12 months, 2 years tops, to figure this out or they will be deep in the shit.  Time is running out.

“Is this really necessary?”

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8 Responses to Profile view

  1. dearieme says:

    It would be interesting to see an NPV calculated for representative examples of the two different profiles. There’s always the arbitrariness of the chosen discount rate, but in this age of low interest rates it should, I suppose, be close to zero.

    • Jake Barnes says:

      I suspect the NPV on Profile 1 would be higher, but that’s half the problem: oil companies have gotten so used to selecting the profiles with the highest NPV that they are frightened to do anything else. The problem is, the challenge facing them is not one of making a development profitable over the full life-cycle of the project, but of reducing the CAPEX down to a level where the cash-strapped partners can afford it *now*. Anybody can buy a mansion for $7m and make money on it long term, but if you’ve not go the money to scrape together the deposit, the whole project is a non-starter. That’s where we are now.

      I confess I don’t know much about the economics of a development, but I do know a bloody expensive facility when I see one: I’ve lost count of how many company or world records I’ve seen broken, or how many times an equipment supplier has had to create a bespoke piece of kit just to meet our requirements. It’s madness.

  2. dearieme says:

    “I suspect the NPV on Profile 1 would be higher”: maybe not. The big, leading negative term, the CAPEX, is smaller in magnitude for your second profile. The extra revenue later on shouldn’t be discounted very much in a low interest era.

    The other way to look at it is one you hinted at: if a firm only has so much capital to spend- the “capital rationing” case, it was called when I was a student – it can run more projects if they, or some of them, have the second profile rather than the first. More projects, each with more modest CAPEX requirements, lets the firm diversify across more countries, more petroleum types, …..

  3. Graeme says:

    Further to dearieme’s comment on the discount rate, I see from Shell’s accounts that their cost of debt is roughly 4%. So after 10 years, income would be discounted to 70% and after 15 years it is worth about 50%. So the long slow decline scenario would be penalised quite heavily in NPV terms even in this era of low interest rates.

  4. Jake Barnes says:

    Good comments both from dearieme and Graeme, this is very informative, thanks.

  5. Graeme says:

    I wonder if you have any experience of predicting/forecasting how fast oil will flow from any particular well or project? Clumsily and without knowing the proper jargon, I am wondering how easy it is to assess what the impact of any given capex profile will have on flow rates. Or even how good are oil companies at working out how to exploit any given oilfield.

    It would be interesting to see whether oil companies are any better than other industries at planning and implementing projects. In telecoms, my experience is that if the guys say it will take 2 months, it will take at least 4 and cost twice as much. And to get things on track tends to lead to things being under-dimensioned, which gives you huge problems a few months down the line as volumes explode.

    • Jake Barnes says:

      I wonder if you have any experience of predicting/forecasting how fast oil will flow from any particular well or project?

      Not much: the production profiles are normally done by the reservoir engineers and well performance guys. I know roughly how they go about their business, but have no direct experience. Their initial data comes from the exploration well(s) and gets revised when they get the data from the appraisal wells (usually 3). They then apply some sort of pareto analysis to give them an idea of how much oil can flow from each well in the reservoir, and how much gas or water injection is required, etc. Although I get the impression that in some companies their departments churn out assumptions masquerading as calculations and the data is fiddled to give management the answer they want to hear.

      Clumsily and without knowing the proper jargon, I am wondering how easy it is to assess what the impact of any given capex profile will have on flow rates.

      I think it would be difficult to calculate with any accuracy, but there is a strong correlation between volumes of liquid (oil, water, and condensates) that need to be handled by a facility and the CAPEX. So if you’re looking to get your CAPEX down, then you would need to be looking at reducing your facility capacity, i.e. flowrates.

      Or even how good are oil companies at working out how to exploit any given oilfield.

      Given that the whole industry is frozen like a rabbit in the headlights because oil prices have collapsed to those last seen in the Middle Ages 2004, I’d say the answer to that is, at this moment, “not very”.

      It would be interesting to see whether oil companies are any better than other industries at planning and implementing projects. In telecoms, my experience is that if the guys say it will take 2 months, it will take at least 4 and cost twice as much.

      That’s the oil industry, and then some. For the past decade, oil companies have had the luxury of throwing another few billion at the job when it all goes tits-up. Now they don’t have that option, they don’t seem to know what to do.

      And to get things on track tends to lead to things being under-dimensioned, which gives you huge problems a few months down the line as volumes explode.

      Ah, that’s never a problem for us: if our facility is undersized, we can debottleneck or add another process train, or expand the facility, or build another. This is generally a good problem to have. What is more of an issue is when the facility is oversized, because somebody either exaggerated the production profile and/or didn’t bother sizing the equipment accurately and just lumped on a contingency just to cover his arse.

  6. Graeme says:

    Thanks for the answer! I guess over-dimensioning rather than “right-sizing” is the name of the game