Value per barrel is a completely hopeless way of putting a price on an oil company or project; but (as with democracy and political systems) unless you have all the detailed facts, numbers and sophisticated tax models it is still the best tool most investors have.
The problems with the metric are legion. For a start, you have to be very clear about where and what the barrels are. Are they sales barrels, in a tanker on the way to Rotterdam; are they producing reserves – still in the ground, but all the development capital invested; are they PUDs (Proven Undeveloped) barrels with all the approvals in place, but no money spent; are they contingent resources, or prospective resources, or what are they? And there are shades of grey in each of those categories, for example lots of 2P (Proven plus Probable) barrels are fully financed and ready to go, and lots are technically and commercially viable but the owner is going to have to dilute their interest to raise the money for the project.
Contingent resources are the hardest to unravel. Sometimes there are great projects classified as 2C which are just waiting for a Government department to issue a piece of paper. Sometimes the contingent resources are "not justified for development", which means that the best development scheme the owners can think of is a project that would lose money. The former are almost as good as 2P reserves, the latter are virtually worthless.
Prospective resources are another kettle of fish altogether – these range from field appraisal opportunities that are probably going to work, to a gleam in a geologist's eye that isn't really worth anything. But one thing unites prospective resources, no-one knows for sure that the oil is there, a well has to be drilled and the exploration money has to be risked before they can be worth more than cents on the barrel. Related: Don’t Read Too Much Into The Rig Count
But let me focus in on just the value of a proven oilfield, and illustrate the difficulty of relying on this one metric. You see, there isn't just one value per barrel for a particular field. The value per barrel varies from the moment the field is discovered until the day it is abandoned. The passage of time, risks getting resolved, the vagaries of the tax system, oil being produced and most importantly of all, the investment of capital, all change the value of the remaining barrels. For a development project, the value climbs as the money is invested until you reach a peak valuation the day before first oil. Then it's downhill all the way. The early barrels are the most valuable as they tend to have tax shelters and low operating costs so, as they are produced, the value of the remaining barrels declines.
Value per barrel for a random project with two phases of capital investment.
In this case, for the same oilfield on a constant oil price assumption, the risked value is varying from as little as $2/bbl, when developing the field seems like a good idea, to a peak of $17/bbl after all the capital investment is completed. Then, once all of the tax allowance, or cost oil in a PSC, is used up, the profit per barrel drops right down. Finally, the value of old mature fields becomes swamped by the impending decommissioning costs and the value per barrel can go negative. So, not all barrels were created equal, the remaining barrels on the same field can be worth anything from $(20)/bbl to $20/bbl, and the value per barrel is critically dependent on where you are in the project lifecycle;
It follows then, that if you are comparing projects as opposed to trying to value a company, that it is important to look at them at the same point in the lifecycle.
When, in a previous post, I was comparing the breakeven points for some UKCS projects, I was effectively looking at all the projects from the point in time that the development of the field started. I included all the capital and all the operating costs, but none of the finding costs. If I throw in some assumptions about tax I can calculate the value per barrel at project approval, for each of those projects. The chart below shows the costs per "discounted barrel" that I have used in my analysis, they are mostly the same as I showed before but I have added a couple of projects, and recalculated Solan based on the Operator's assumptions.
Remember, the reserves on this chart are discounted reserves, calculated using a 10% discount rate, think of the green blobs as net present volume. It makes a big difference, Catcher has a field life of about 11 years, Bentley more than 35 years, so everything else being equal, which of course it isn't, a Catcher barrel in the ground is worth approximately twice as much as a Bentley barrel in the ground.
Capex & quality discount not discounted; Opex & reserves discounted at 10%.. Skipper, Lancaster & Bentley 2013 CPR; Catcher Premier pres. March 2014; Kraken Enquest pres. Nov 2013; Western Isles Dana pres. Nov 2014; Mariner Statoil pres. Dec 2012 (quality discount estimated). Golden Eagle GEAD EIS Dec 2010 & Press Releases; Solan, Chrysaor CPR June 2014, adj per Premier presentation Feb 2015, reserves 42 mmboe capex $1.7bn; Clair Ridge & Kinnouil BP press releases & EIS. Alma/Galia Enquest reports and presentations; Rosebank capex, press reports of $10bn, & reserves of 275 mmboe, OMV E&P presentation Feb 2014. If Opex data unavailable, Opex estimated at 4.5% of Capex p.a. (except Kinnouil). Pilot based on internal Steam Oil Production Company estimates as of February 2015.
By the way, did I mention that the value per barrel varies with whatever assumption you make about long run oil prices? I guess I didn't have to. So let's do the calculation of value per barrel for a range of long run oil prices. I do this by taking the oil price per barrel, subtracting the discounted costs per barrel and multiplying by one minus the tax rate, that gives me a profit per discounted barrel. To make the chart I then multiply by the number of discounted barrels to get the overall project value and then divide by the number of regular barrels to get a value per actual barrel that can then be compared across all the projects. That is petroleum economics as simplified as I can make it.
Value per barrel of 2P (or equivalent) reserves at the point of project sanction versus long run oil price assumption
Anyway after all those machinations, we get lots of lines all over the chart. You see, every project has a different breakeven value (where the green line crosses the $0/bbl line) and the slope of the green line depends on two things, the effective tax rate and how long it is going to take for all the oil to be produced. I added Johan Sverdrup to the list, as its development plan has just been submitted, and I thought you might be curious to see how it compares to projects in the UK such as Clair Ridge, Catcher or Mariner. With a marginal tax rate of 78% the value per barrel is really quite modest, of course it helps to have a couple of billion of them. Related: How Much Crude Oil Do You Consume On A Daily Basis?
Now I need to put in a warning, despite all that complexity, there are many simplifying assumptions made so that I can effectively run petroleum economics for fourteen oilfields at eight different oil price assumptions in a micro second without detailed production profiles or tax models. So the absolute values aren't precise; on average the value per barrel I calculate tends to be a bit less than a proper tax model will give, and the relative comparisons are only as good as the data I have and the tax assumptions I made.
In any event, the only value that really matters is what someone is prepared to pay. There are a few fields where you can work out a value from the company's share price and a few fields where the terms of a transaction have been published. So I have added those on to the chart to see how the actual values compared to my calculations. I posted the value per bbl against the oil price prevailing at the time the deal was struck, and adjusted carry based deals to give the buyer the full tax benefits of that structure.
Value per barrel of 2P (or equivalent) reserves at the point of project sanction versus long run oil price assumption with certain transactions highlighted
Xcite is one of the few instances where the enterprise value of the company should match the net present value of the discounted cash flows from the project. Of course it doesn't, which is why the bulletin boards are full of heated debate, to which my contribution is precisely nothing, as all I have done is rejig the numbers in the CPR. For those that don't believe me (and I fear that will be quite a few people) the weighted average oil price in the Bentley CPR is about $118/bbl (weighted so that the oil price in the near term matters more than the oil price in the long term). It is off my scale but the NPV/bbl I get for an average price of $118/bbl is $8.3/bbl. The CPR says it should be $8.2/bbl, that they are so close is more good fortune than good judgement, but there is a degree of consistency. I have included a data point for Hurricane as well, but to calculate the market value per barrel, I only used Lancaster reserves.
Dyas's recent farm-in to Catcher, Enquest's 2012 acquisition of Canamen's and Nautical's stakes in Kraken and Statoil's 2010 purchase of a stake in Mariner from Nautical are all straightforward enough deals to post on the chart with some (but not much) confidence. Only the Statoil acquisition of Mariner looks expensive, but apply the recovery factor I think Statoil might actually get in Mariner (which would drag the dark blue line well up the chart) and that deal could look pretty good too.
So what's the conclusion. Well, value per bbl is a lousy metric, almost hopeless for comparing deals and valuing companies, but still better than anything else I can think of.
By Steve Brown for Oilprice.com
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