On December 4, 2014, the Canadian Securities Administrators published Amendments to National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and those amendments became effective July 1, 2015. This blog is the second in a series that will describe the significant changes as seen through the eyes of a qualified reserves evaluator (QRE). Read the first one here.
Part 2: Disclosure by Product Type
The Amendments result in new, revised or deleted product types which impact reserves reporting. Some of these revisions are inconsequential; however, there are three items that create significant interpretational issues and potential product transfers between product types. We will examine these and suggest some solutions that we believe will satisfy disclosure requirements.
Conventional Natural Gas versus Shale Gas
Conventional Natural Gas is a modified product type where the term “conventional” was added to the term “natural gas” to create a new product type. In simple terms, ROTR defines conventional as resources that flow without stimulation and unconventional as resources that require stimulation. Informal guidance from the Alberta Securities Commission (ASC) is to disclose natural gas in low permeability accumulations typically requiring hydraulic fracturing to be economic as Shale Gas.
By definition, shale gas is natural gas contained in dense organic-rich rocks, including low-permeability shales, siltstones and carbonates, in which the natural gas is primarily adsorbed on the kerogen or clay minerals, and that usually requires the use of hydraulic fracturing to achieve economic production rates.
A complexity arises because many resource accumulations commonly categorized as unconventional, and requiring development by multi-stage fractured horizontal wells, do not fit the definition of shale gas. After much discussion with other QRE firms, we have taken the position that natural gas reserves and resources from plays with some organic content (for example, the Montney) plus obvious shale plays (Horn River and Duvernay) should be classified as shale gas. On the other hand, we believe that natural gas resources from plays with little organic content, like the Cretaceous (Cardium, Viking, Spirit River, Mannville, etc.) and shallower, should be classified as Conventional Natural Gas.
Significant natural gas resource volumes previously classified as natural gas within a low permeability resource play (the Montney for example) will now be classified as shale gas by most evaluators, but likely not all, creating some inconsistency in reporting.
Tight Oil versus Light and Medium Crude Oil
Tight Oil is a new product type that includes shale oil and oil recovered from low permeability plays that requires stimulation to flow. However, a potential area of interpretation difficulty arises where areas of some long-established conventional fields that consist of low permeability reservoir, such as the outer halo or underlying sequences of the Pembina Cardium Field, are now being exploited using unconventional methods. It is our position that the crude oil produced from plays that had been previously developed with vertical wells, where the lower permeability reservoir portion is now being developed with multi-stage fractured horizontal wells, should be classified as Light and Medium Crude Oil. Crude oil produced from plays that are predominantly developed with multi-stage fractured horizontal wells (for example, the Bakken and Montney plays) should be classified as Tight Oil.
A further complexity is how to handle the solution gas produced along with tight oil. Since there is no Tight Gas bin, we suggest lumping this with the conventional natural gas unless the tight oil is, in fact, shale oil; then it should be classified as Shale Gas.
Heavy Crude Oil
The revised definition for the product type Heavy Crude Oil may cause some product transfers from Light and Medium Crude Oil to Heavy Crude Oil, and vice versa. Heavy Crude Oil is now strictly defined as crude oil with a relative density greater than 10° API gravity and less than or equal to 22.3° API gravity. Previously, heavy oil was oil that either met the gravity definition or qualified for royalties specific to heavy oil in a jurisdiction that had a royalty regime specific to oil density.
In Saskatchewan, heavy oil, in a royalty context, is defined as oil produced from wells located in townships north of Township 21 in Ranges 5 through 29, East of the Third Meridian. Crude oil produced in other areas of Saskatchewan was classified as light and medium crude oil. With the revised definition, some crude oil produced in Southern Saskatchewan that was previously classified as light and medium crude oil will now be classified as heavy oil.
In Alberta, heavy oil for the purpose of calculating royalty is defined as oil with a gravity that is greater than 21.5° API and less than 25.7° API. In British Columbia, heavy oil for the purpose of calculating royalty is defined as oil with a gravity that is equal to or less than 27.5° API and greater than 10° API. Significant oil volumes with gravity greater than 22.3° API, but less than the upper limit in a royalty context in Alberta and British Columbia which were previously classified as heavy oil, will now be classified as light and medium crude oil.
Foreign jurisdictions also have different definitions for heavy oil. In Colombia, for example, heavy oil for the purpose of calculating royalty is defined as oil with a gravity that is equal to or less than 15° API. Significant oil volumes previously classified as light and medium crude oil will now be classified as heavy oil for Canadian reporting purposes.
There will be natural gas production from certain plays developed using unconventional methods that will be classified as conventional. This disconnect could easily be solved by introducing a tight gas product type comparable to how tight oil is handled.
In the case of tight oil, some evaluators may be tempted to classify certain plays as light and medium crude oil for the vertical well development and tight oil for the adjacent or underlying horizontal well development. We suggest avoiding this by classifying the entire development in accordance with the initial development configuration.
For heavy oil, there is inconsistency between what is classified as heavy oil for royalty purposes versus reporting purposes. This may cause some confusion in jurisdictions where companies are required to report to both securities commissions and to regulatory authorities.
For reserves reconciliations, the opening balance for reserves reporting must remain unchanged from the previous evaluation. We recommend inserting a product transfer line in the reserves reconciliation to show the changes to the opening balance resulting from the new product definitions.
Reporting issuers should choose the closest product type if the substance produced does not exactly match one of the product types or if it matches more than one of the product types listed in NI 51-101. A reporting issuer must ensure that its disclosure is not misleading and will have to consider whether additional explanation is required to provide the necessary context.
Stay tuned for Part 3 of this series: Disclosure of Contingent Resources.
The author of this post, Keith Braaten, has been President and CEO of GLJ since 2011. He has more than 36 years of petroleum related experience in Canada (including frontier areas) and over 25 countries worldwide.
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