Reserves, resources and why you should care
9 July 2018
Reserves and Resources. Some of the terminology in the E&P sector is not particularly intuitive. One of the first and most important sets of data to get a feel for, however, is what all E&P companies are looking for and that is, oil and gas reserves and resources.
What are they? At a high level, 'reserves' can be defined as commercially recoverable volumes of hydrocarbons, i.e. they have been discovered, they have been appraised and they have been shown to be economically recoverable. 'Reserves', rightly so, have tangible value. On the other hand, 'Resources' are less mature and in some instances are yet to be discovered. As such, they are inherently more risky, which from a ‘value’ perspective means they do not attract anywhere close to the same market or industry ‘value’ as reserves.
There are three main reserve and resource categories
1.Reserves – “are those quantities of petroleum anticipated to be commercially recovered from known accumulations from a given date forward”, i.e. a discovery has been made, it has been sufficiently appraised and a company has shown it has both the technical and commercial capability to develop the appraised hydrocarbons.
2.Contingent Resources – “are those quantities of hydrocarbons estimated to be potentially recoverable from known accumulations, but where the project is not yet considered mature enough for a commercial development”, i.e. a discovery has been made but it has not been sufficiently appraised to call it a commercial oil/gas field.
3.Prospective Resources – “are quantities of hydrocarbons estimated to be potentially recoverable from undiscovered accumulations by the application of future development projects”, i.e. what a company thinks might be there, but an exploration well has not yet been drilled.
In order to migrate from oil in place to recoverable resources/reserves, a ‘recovery factor’ (Rf) must be applied. Typical recovery factors for oil fields can range from between 10% and 60%, with the wide variance being explained by the differing fluid and reservoir characteristics within different accumulations.
Remember: 'reserves' are commercial and have been appraised, while 'resources' (whether contingent or prospective) require more work to be considered as commercial, and STOIIP is even more uncertain.
So what’s the problem?
From an investor’s perspective, this is a challenging time as it’s often the stage at which an inaccurate description or an unbalanced representation of the data/interpretation introduces uncertainty. This naturally makes it harder to decipher the significance of an announcement and also, therefore, to make a subsequent adequately informed investment decision.
Petroleum Resources Management System
Prospect and leads
The ‘chance of success’
Example “1 in 10” chance of success calculation for XYZ exploration prospect:
GCoS = P(Source) x P(Seal) x P(Reservoir) x P(Trap) x P(Migration)
GCoS = 0.6 x 0.65 x 0.65 x 0.65 x 0.6
GCoS = 10%
The CoS percentage is not only important from a conceptual perspective, it is also used during the process of prospect ranking, i.e. when trying to decide which prospects to drill within a portfolio.
In the same regard, another measure that helps the exploration drilling decision-making process is the calculation of what is called the ‘Expected Monetary Value’, or EMV of a prospect. All else being equal, prospects that have the highest EMVs usually become the focus of future exploration drilling.
Expected Monetary Value (EMV)
A prospect EMV is defined as: EMV = (NPV x GCoS) – (DHC x 1-GCoS), where DHC is the ‘dry hole cost’ of drilling the well. It is essentially a prospect’s NPV risked for exploration drilling capex and is one of the industry standard approaches for prospect ranking and risk assessment.
Oil and Gas units
In a nutshell: oil is measured in barrels (bbl) and gas is measured in cubic feet (cf), so far so good, but what is a ‘barrel of oil equivalent’ (boe)?
It is common, but not always good practice, to covert volumes of gas into equivalent volumes of oil so as to enable a more straightforward comparison between oil and gas volumes. The ‘gas conversion factor’ is roughly 5.6, which means in order to show volumes of gas in oil terms, you simply divide by 5.6.
Oil to Gas
- 1 bbl = 5,600cf
- 1 MMbbls = 5.6Bcf
- 100MMbbls = 560Bcf = 0.56Tcf
- 1,000MMbbls = 1Bnbbls = 5.6Tcf
Gas to Oil equivalent (divide by 5.6)
- 300Bcf = 53.6MMboe
- 3Tcf = 536MMboe
- 30Tcf = 5.36Bnboe
Reserves are the best, followed by contingent resources and then prospective resources. Some companies don’t always present a consistent description of the resources (or the associated risks) that comprise their ‘assets’ and so it is imperative to establish exactly what it is that you’re assessing!
Whether a misrepresentation occurs by design, incompetence or simply by mistake, from a prospective investor’s perspective, it is critical to know the difference between reserves, contingent resources, prospective resources, in-place resources, prospects, leads and why you need a recovery factor, what the appropriate units are and how geological risks are determined and applied.
Red flags should start to appear if you read company statements that make overly bullish references to gross unrisked STOIIP (in-place) volumes, or talk disproportionately positively about the P10 prospective resource potential upside of their acreage.
There are well over 100 listed E&P companies on the LSE, so there is naturally significant variability in the manner and quality in which they present the data that lies at the heart of their businesses. Knowing precisely what is being described and being able to filter out those that do not present it to a high enough standard is therefore of paramount importance. Forearmed is forewarned!