Split Conditions and Split Classification
The revised PRMS contains clear wording on its position that split classifications are not permitted. This means that a project cannot have quantities classified in both Reserves and Contingent Resources (e.g. 1C, 2P, 3P). This is important when addressing the situation where a project is economic and commercial in the P50 (2P) case (and can therefore be claimed as Reserves), but is neither commercial nor economic in the P90 (1P) case. In this instance, an entity may claim 2P and 3P Reserves for the project, but no 1P Reserves. Neither can these ‘1P’ volumes be claimed as Contingent Resources.
Furthermore, the revision is clear that one should not apply different commercial conditions when categorising resources, in effect mixing chance of commerciality (classification) with uncertainty (categorization). This is referred to as split conditions and typically would result in Probable and Possible Reserves being assigned without Proved Reserves. An example of this is discussed with respect to contract extensions later in this article.
Project Work Scope
Although the revised PRMS defines a project as a tangible work programme (e.g. single well development, 5 well infill programme, adding gas compression), it goes on to specifically state that for Contingent Resources and Prospective Resources, different project scopes may be used. This is done to reflect the development uncertainties associated with immature projects.
Fuel Volumes are Reserves
Produced petroleum volumes used for fuel are termed Consumed in Operation (CiO) volumes. Under the 2007 PRMS, these volumes could only be included as Reserves if the country’s regulator allowed it. Under the revised PRMS, CiO volumes may be included as Reserves for any project, but must be reported separately. It is stated though, that CiO volumes must not be included in project economics as they do not have an associated cost or revenue. Instead, CiO volumes are considered to remove the need to purchase fuel and their only impact should therefore be the lowering of operating costs.
Historically, Reserves volumes have typically been considered to be those for sale. Therefore, when CiO is included in reserves volumes, clear presentation of the CiO in all reserves summary tables will be important to show what volumes contribute to the revenue. This will include those for press releases and investor presentations.
Determination of a Discovery
In the revised PRMS, the requirements for a discovered petroleum accumulation have changed slightly It states that “in the absence of a flow test or sampling, the discovery determination requires confidence in the presence of hydrocarbons and evidence of producibility, which may be supported by suitable producing analogs”.
There are two interesting aspects to this: firstly, ’evidence of producibility‘ is now explicitly mentioned as being a requirement of a discovery; and secondly, in addition to testing, sampling and/or logging, that suitable producing analogues may now be used. This is a necessary change for unconventional assets, but the change should also make it easier to disclose discoveries of untested conventional petroleum in areas where analogous reservoirs have produced hydrocarbons. Quantitative assessment of analogues, such as that described in SPE paper 102505, will become increasingly important.
Economic vs Commercial
It is now made clear that the economic determination of a project should use a 0% discount rate and that a project with a positive undiscounted cumulative net cash flow is considered economic. It is also made clear that the test for economic producibility should exclude Abandonment, Decommissioning and Reclamation (ADR) costs.
In order for an economic project to be considered commercial, a further set of conditions must also be met:
- Evidence of a technically mature, feasible development plan
- Evidence of financial appropriations at least having a high likelihood of being in place
- Evidence to support a reasonable time-frame for development (typically less than 5 years, but longer may be justifiable)
- A reasonable assessment that the project(s) will have positive economics and meet defined investment and operating criteria
- A reasonable expectation that there will be a market for forecast sales quantities
- Evidence that the necessary facilities are available or will be available
- Evidence that all relevant approvals are in place or will be forthcoming
Importantly, the revised PRMS makes it clear that the commerciality test is generally applied to the Best Estimate (or P50) forecast. The Low Case may be used when it forms the basis for the entity’s project decision making, but use of the High case alone is not permitted.
Assuming that all the criteria listed above are met, and there is sufficient commitment to an economic project, Reserves can be attributed.
Contract Extensions and Renewals
The revised PRMS removes the possibility of reporting split conditions for volumes beyond contract expiry. In the 2007 PRMS, where there was not a significant risk of the cessation of rights to produce, evaluators could categorise quantities beyond the contract expiry as Probable or Possible Reserves (without assigning Proved Reserves). This paragraph is removed entirely from the revised PRMS, meaning that unless there is reasonable expectation that an extension, a renewal, or a new contract will be granted, volumes beyond the expiry should be classified as Contingent Resources, with a reduced chance of commercialisation. In the assessment of whether Reserves or Contingent Resources can be assigned beyond the current contract expiry date, evaluators will still need to consider risks regarding including reassignment of acreage to new parties, changes in working interest or changes in PSC contractual terms.
An entity’s entitlement volumes are ultimately defined by the terms of the contract under which they are permitted to recover hydrocarbons. Such contracts are typically based on either a tax-royalty model or a Production Sharing Contract (PSC).
The 2007 PRMS is not definitive on the reporting of entitlement volumes. The revised PRMS states that “an entity's net recoverable resources are the entitlement share of future production legally accruing under the terms of the development and production contract or license”. Furthermore, in order to determine net revenue and commerciality, the net entitlement recoverable resources must be used.
Previously there has been some confusion as to which net recoverable resources should be evaluated and reported. Some entities chose to solely report net recoverable resources based on their working interest share of the total recoverable resources less royalties, regardless of whether this is equivalent to their net entitlement recoverable resources.
Under tax-royalty regimes, the net entitlement recoverable resources are the entity’s working interest share of the property’s gross petroleum sales, after deducting royalties and any interests in production payable to others. However, in other fiscal regimes, particularly in PSC regimes, this is not the case.
In PSCs, the entity’s revenue is based on their entitlement share of produced hydrocarbons, which takes into account cost recovery schemes and production splits with the host Government. The net entitlement recoverable resources are then typically less than the net working interest recoverable resources. Furthermore, in order to determine revenue and commerciality, the net entitlement recoverable resources must be used.
This clarification of net recoverable resources in the revised PRMS should lead to the routine disclosure of net Reserves based on entitlement volumes.