header
search-icon
mobile-menu-icon search-icon

RESEARCH

Clients can browse and search the Peel Hunt research library and archive.

TRADING

A tool for our clients to submit and manage orders with Peel Hunt. 

REGISTER FOR OUR RESEARCH PORTAL

Thank you, your registration has been received.
We will be in contact with you shortly.

I'm interested in (tick all that apply)

SEARCH

PEOPLE
SERVICES
NEWS

Advisory and broking services to UK mid & small-cap companies

Comprehensive coverage of over 300 companies

Investment ideas and execution for institutional investors

Complete UK pricing coverage and worldwide access

Insight Image

STOIIP, collaborate and listen!
7758 Ah∅(1-Sw)/Boi. This is the equation used to calculate the volume of oil initially in place in a reservoir, also known as Stock Tank Oil Initially In Place, or STOIIP. This is NOT the same as the volume of oil that can be recovered from a reservoir. For this, you need to multiply by an estimated recovery factor (Rf). It is also not the same as the prospective resource a company might present before it drills an exploration well. Knowing the difference is essential. There is often significant variance in: (1) the loose definitions that some companies apply to their resource bases; and (2) the consistency of terminology with respect to how their ‘resources’ are presented. This short report aims to set the record straight and to provide investors with a brief reference point to enable a quick judgement to be made on just how significant, or not, a company’s resource base might be, based on the ‘reserve’ and ‘resource’ estimates they present to the market.

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.

STOIIP
Even less mature (and therefore more uncertain) than prospective resources, is the total potential volume of oil initially in place within a reservoir before the commencement of production. This is known as Stock Tank Oil Initially In-Place, or STOIIP. Oil in-place must not be confused with oil reserves that have been shown to be technically and economically recoverable.
Having a sense of the different classifications of reserves and resources is therefore important. It isn’t necessary to memorise the STOIIP formula, but it would be helpful to have a vague understanding of the different parameters that comprise it. Therefore, to repeat the title of this note:
                                                 7758 AhØ(1 – Sw)/Boi
Where: 7758 = conversion factor from acre-feet to barrels
A = area of reservoir in acres taken from maps
h = height or thickness of net pay zone taken from log data
Ø = porosity percentage taken from log data
Sw = water saturation volume in reservoir pore space measured as a percentage
Boi = oil formation volume factor required to convert surface oil volumes to reservoir conditions

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?
Almost all oil and gas sector RNS's refer to either 'reserves', 'contingent resources' or 'prospective resources' in connection with the company’s operations. Typically, reference will be made to reserves or resources in the description of various data acquisition activities aimed at defining an ‘assets’ resource potential, often where a lot of the confusion comes in, at the early stages in the prospect evaluation process where the company will attempt to articulate:
  1.Having ‘worked up’ their lead/prospect inventory from various geological studies and data analysis, what the    volume of hydrocarbons they think might be in the subsurface or,
  2. Having drilled an exploration/appraisal well and based on the preliminary data acquired, what the volume of discovered hydrocarbons might be.

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
For those interested, click here (from page 7 onwards) to the Society of Petroleum Engineers document, where there is a full description of the petroleum resources management system, which provides a framework for the classification of all petroleum resources.

Prospect and leads
As with reading the fine print behind the definitions of reserves and resources, also knowing the distinction between a ‘lead’ and a ‘prospect’ is crucial. A ‘prospect’ is a specific trap that has been identified and mapped but has not yet been drilled, whereas a ‘lead’ is a possible trap, but where sufficient data has not yet been acquired to fully map it and is therefore substantially less mature. Often additional geological data such as 2D or 3D seismic is required in order to promote a lead up to drillable prospect status.

The ‘chance of success’
Within prospect evaluation, once all of the geological analysis and interpretations have taken place, it is standard industry practice to then apply a ‘geological chance of success’ (GCoS) in order to characterise the chance of making a hydrocarbon discovery. The chance of success is often expressed as a percentage (%GCoS) and is determined by multiplying the probabilities (P) of the individual petroleum system element risks together.

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
The E&P sector is littered with technical jargon that can often make it seem quite opaque, but one of the other basic areas to get to grips with is the units in which volumes of oil and gas are measured. The oil industry uses Roman numerals for units of volume such that 1,000 = M and 1,000,000 = MM.

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

Conclusion
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!