Deals Aren’t What They Seem
When companies announce the purchase or sale of exploration and production assets, the acquisition cost often includes the cost of assets that are unrelated to reserves in the ground. In addition, while the company may quote a proved reserve figure in the deal announcement, there are probable, possible, contingent or ‘potential’ reserves that are included in the deal as well. Simply dividing the total acquisition cost by the announced proved reserves in the deal would overstate the price the company was paying for proved reserves because it was also gaining much more besides.
In order to get to the real or underlying (what some analysts call the “Implied”) cost of oil and gas reserves, Evaluate Energy has developed a transparent methodology for adjusting deal acquisition costs This article describes the adjustments we make. As this is most definitely a mixture of art and science, we welcome your feedback.
We use these adjustments to provide clients with access to our M&A database the ability to compare deals on a more comparative basis than is possible with the normal metrics, although these are also included.
Adjustments to Reserve Values
There are a variety of standard ways of valuing the element of a deal that isn’t associated with the proved reserves or producing assets. We give preference to disclosure on probable, possible or potential reserves as this is a more accurate indicator of the value than the size of the land (as we don’t always know the prospectivity, especially within new oil and gas plays).
A conventional approach is to apply a standard $ per probable/potential barrel for all deals, irrespective of when the deal took place. So, for example, the probable reserves of a deal done in 2005, when crude oil prices were far lower than they are now, would be valued, under this methodology, the same as an equivalent volume of reserves selling today. In a market where oil and gas prices are fluctuating widely, this approach appears too static and will give misleading results.
So instead, we apply a multiplier to benchmark oil and gas prices at the time of the deal announcement. This is to roughly account for the changing valuation of any upside to a deal i.e. probable boe should be valued higher in a +$100 per barrel environment than a $40 per barrel environment. The multipliers we use change according to the region. The multiplier is loosely based on our knowledge of risk, tax and access to markets via the location and infrastructure in place. So for US/Canadian deals, the ratios applied are:
Probable boe: 10% of current benchmark prices
Possible boe: 5% of current benchmark prices
Contingent boe: 2.5% of current benchmark prices
“Potential” boe: 1-2% of current benchmark prices
Also the ratio is applied to a blended WTI/Henry Hub price based on the oil weighting of the reserves or, failing that, production. This is to try to account for the far lower valuation of gas reserves. So if we have a US deal with 50 million boe of probable reserves which is 50% oil and 50% gas and the WTI price is $100 and gas price is $4.00, the blended price would be $62 per boe and the valuation of those reserves would be $310 million. This value would then be used to normalise the cost per 1P and cost per producing barrel. That is, this amount would be deducted from the total announced deal value before dividing through by the announced volume of proved reserves in the deal. The same method is used for possible, contingent and potential reserves but with a lower multiplier (as shown in the table above) to reflect the lower chance of success of those reserves.
If the reserve upside is not reported we take the area of exploration land and multiply by a $/acre based on comparable deals in the region, if there are any, or failing that, a standard cost per acre relative to the country in which the deal took place.
Adjustments for non E&P Items
Non-upstream elements to a deal could include a refinery and marketing operations, pipelines, gas processing, power plants or even financial elements such as accrued tax losses or, in Canada, tax pools. We have established internal guidelines on how to value these based on actual deals done. So we have generic measures of $/km of pipeline, a $ per service station, $ per MW of power plant capacity, $ per barrel of distillation capacity and so on which may then be further adjusted to account for political or country risk.
If the deal is a corporate deal and the target company has reports a detailed segmental breakdown of profit we use an earnings multiple for the value of the non upstream segment. This is usually EBITDA for the segment multiplied by the total deal EBITDA multiple (consideration divided by total EBITDA). If the EBITDA multiple doesn’t look standard (due to the company having a lot of assets which aren’t onstream and therefore not reflected in the earnings) we use a standard multiple, usually around 6. Again this changes according to the region, as the higher the tax the lower the EBITDA multiple would be.
As well as a comprehensive M&A database, Evaluate Energy undertake reserve and deal valuations for a variety of clients as well as oil and gas consultancy work.