BCN 2003/30 - Advance Notice of Adoption of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and Related Documents [BCN - Rescinded]
The Commission and other members of the Canadian Securities Administrators (the CSA) plan to adopt National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (including related forms) (the National Instrument) and related Companion Policy 51-101CP (the Policy). The related forms are Forms 51-101F1, 51-101F2 and 51-101F3. Form 51-101F3 is not being adopted in British Columbia. The full text of the National Instrument (including the forms) and the Companion Policy are reproduced on the Alberta Securities Commission website at www.albertasecurities.com.
In most CSA jurisdictions, the National Instrument is being implemented as a rule or commission regulation, effective on September 30, 2003. In Québec, the National Instrument is being implemented as a Commission policy, pending ministerial approval for implementation of the National Instrument as a rule.
In conjunction with the implementation of the National Instrument, National Policy 2-B Guide for Engineers and Geologists Submitting Oil and Gas Reports to Canadian Provincial Securities Administrators (NP2-B) is being rescinded and consequential amendments are being made to other national, multilateral and local securities legislation and policies.
If the required government approval is obtained in British Columbia, the Commission intends to implement the National Instrument as a rule and to adopt the Policy and the consequential amendments to the Securities Rules, effective September 30, 2003.
Substance and purpose of the National Instrument
The National Instrument establishes a regime of continuous disclosure for reporting issuers engaged in exploring for, developing or producing oil or gas. The purpose of the National Instrument is to enhance the quality, consistency, timeliness and comparability of public disclosure by reporting issuers concerning their upstream oil and gas activities (meaning activities before the oil or gas is transported, refined and marketed).
The National Instrument establishes disclosure standards and procedures somewhat akin to those applied to financial disclosure. It prescribes standards for the preparation and disclosure of oil and gas reserves and related estimates, and requires the annual public filing of certain of those estimates and other information pertaining to oil and gas activities. The National Instrument supplements disclosure requirements that apply to reporting issuers generally.
Comments on the National Instrument
The CSA published a revised version of the National Instrument (the 2003 Proposal) on January 24, 2003 (March 21, 2003 in Québec).
We received 16 comment letters on the 2003 Proposal. The majority of commenters expressed support for the National Instrument or its objectives. The comments on the 2003 Proposal, and our responses, are summarized in more detail in Appendix A to this Notice.
The National Instrument incorporates a limited number of changes from the 2003 Proposal.
Most of the changes were made to enhance clarity:
- Additional explanation in the Companion Policy and expanded definitions in the Glossary are meant to resolve ambiguities.
- We have clarified that a reporting issuer is responsible for disclosing in its annual filing made under the National Instrument its estimated total abandonment and reclamation costs, but that the reserves-related future net revenue estimates themselves need reflect only those abandonment and reclamation costs that relate specifically to well abandonment.
We have streamlined some of the annual disclosure by scaling back:
- the list of product types for which separate disclosure is required; and
- the multi-year annual breakdowns of elements of estimated future net revenue.
To make the required disclosure more meaningful, while at the same time avoiding the need for some problematic and potentially misleading cost allocations, disclosure of future net revenue estimates is to be provided for the reporting issuer as a whole and by production group - the aggregate of products produced together from a single well or reservoir - rather than separately for each of the products.
A more detailed discussion of the changes from the 2003 Proposal is set out in Appendix B to this Notice.
Sections of the National Instrument that require the board of directors to follow specific procedures in preparing the required reports and that recommend that the board establish a reserves committee will not apply in British Columbia. Also, as noted above, Form 51-101F3 is not being adopted in British Columbia.
Consequential amendments to other instruments
In consequence of the implementation of the National Instrument and the rescission of NP 2-B, amendments are being made to other securities legislation and securities directions. These amendments eliminate current references to NP 2-B. In some cases those references are replaced by references to the National Instrument. In other cases, the conversion to a continuous disclosure regime under the National Instrument eliminates the need to make specific reference to oil and gas disclosure in the amended document.
The amendments come into force at the same time as the National Instrument, on September 30, 2003, but their effect is in most cases phased in issuer-by-issuer, as each reporting issuer becomes subject to the National Instrument (see Timing and transition below). Transitional provisions are incorporated, where necessary, in the specific consequential amendments. In all cases, the transition is completed not later than June 30, 2005.
The text of the consequential amendments will be published concurrently with the Final Notice of Adoption of the National Instrument.
Timing and transition
Application of the National Instrument, the rescission of NP 2-B, and the other consequential amendments are being phased in. Most reporting issuers will become subject to the National Instrument in 2004, and the process will be completed by June 30, 2005.
Timing of the transition for a particular reporting issuer will depend on:
- its financial year-end;
- when it first files certain types of disclosure documents; and
- whether it opts voluntarily to become subject to the National Instrument earlier than required.
A reporting issuer’s transition to the National Instrument will generally occur when it files, or is required to file, its audited financial statements for its first financial year that ends on, or includes, December 31, 2003. At that time the reporting issuer must file its annual disclosure under the National Instrument. From that time, the reporting issuer also becomes subject to the other provisions of the National Instrument and (by the operation of transitional measures built into consequential amendments to other securities legislation and policies) to amended prospectus and other distribution disclosure requirements that substitute references to the National Instrument for current references to NP 2-B.
Because prospectus disclosure requirements include information relating to oil and gas activities, and because the filing of a prospectus more than 90 days after the end of a reporting issuer’s financial year can trigger an accelerated filing of its annual financial statements, the filing of a prospectus could itself similarly accelerate a reporting issuer’s first filing obligations under the National Instrument.
Examples of Timing
Taking as an example the current typical 140-day filing deadline for audited annual financial statements, and a reporting issuer with a calendar financial year, the transition to the National Instrument would apply in or before May 2004. The reporting issuer would make its first annual filing under the National Instrument at the same time as it files its annual financial statements for 2003. After that, it would be fully subject to the National Instrument and to the consequential changes to prospectus and other rules, and it would cease to be subject to NP 2-B.
If, however, the same reporting issuer files a prospectus during the first 90 to 140 days of 2004, it would have to include in its prospectus annual financial statements for 2003, even though the normal financial statement filing deadline has not yet occurred. The reporting issuer’s transition to the National Instrument would be similarly accelerated: its first annual filing under the National Instrument would be due at the same time, the prospectus would include the same information from that filing, and NP 2-B would not apply.
If the shorter financial statement filing deadlines contemplated in proposed National Instrument 51-102 Continuous Disclosure Obligations (the CD Rule) are implemented for financial years ending on December 31, 2003, those shorter deadlines (90 days after year-end, or 120 days for venture issuers) would also apply to filings under the National Instrument. In that case, the transition to the National Instrument for non-venture reporting issuers with calendar financial years, including their first annual filing under the National Instrument, would occur by the end of March 2004. (See the CSA Notice published on June 20, 2003, concurrently with the proposed CD Rule. Consult the BCSC website for future developments concerning the CD Rule.)
Interim use of CIM reserves definitions
Pending the application of the National Instrument to a particular reporting issuer, NP 2-B will continue to apply to that issuer.
During that interval, the securities regulatory authorities or regulators will accept and encourage the use of the Petroleum Society of the Canadian Institute of Mining, Metallurgy & Petroleum (the CIM) reserves definitions set out in the Canadian Oil and Gas Evaluation (COGE) Handbook for purposes of NP 2-B, rather than the reserves definitions set out in NP 2-B. An issuer that wishes to exercise this option should advise the regulator in a covering letter accompanying each preliminary prospectus or other document being filed for which NP 2-B is relevant. Each such document in which the CIM definitions are used should also identify and describe the relevant reserves classifications.
Because the CIM definitions incorporate target certainty levels, securities regulatory authorities or regulators would not require an issuer using the CIM definitions to reduce reasonably estimated probable reserves by applying an allowance for risk as currently specified under NP 2-B, but the absence of such a reduction should be stated. When estimating reserves and related future net revenue using constant prices and costs, an issuer that uses the CIM definitions should use prices as at the end of its financial year.
You can obtain further information from any of the following:
Senior Legal Counsel
Legal and Market Initiatives
British Columbia Securities Commission
Telephone: (604) 899-6792
Fax: (604) 899-6814
Glenn Robinson, P.Eng.
Senior Petroleum Evaluation Engineer
Alberta Securities Commission
Telephone: (403) 297-4846
Fax: (403) 297-2210
Alberta Securities Commission
Telephone: (403) 297-7274
Fax: (403) 297-6156
Appendix A - Summary of Public Comments on the 2003 Proposal and CSA Responses
Appendix B - Summary of Changes from the 2003 Proposal
August 1, 2003
Douglas M. Hyndman
This Notice may refer to other documents. These documents can be found at the B.C. Securities Commission public website at www.bcsc.bc.ca in the Commission Documents database or the Historical Documents database.
Advance Notice of National Instrument 51-101
Standards of Disclosure for Oil and Gas Activities and Related Documents
Summary of Public Comments and CSA Responses
The CSA received written comments on the version of the National Instrument 51-101 (“NI 51-101”) and the related Forms and Companion Policy (together, the “Instrument”) published on January 24 (on March 21 in Québec), 2003 (the “2003 Proposal”) from the following 16 commenters:
1. AIM Trimark Investments - April 1, 2003
2. APA Petroleum Engineering Inc. - March 31, 2003
3. Canadian Institute of Mining, Metallurgy and Petroleum, Standards Operating Group - March 10, 2003
4. Carscallen Lockwood LLP - March 31, 2003
5. EnCana Corporation - April 4, 2003
6. Fraser Milner Casgrain LLP - March 31, 2003
7. Imperial Oil Limited - March 31, 2003
8. Kozowyk & Associates - March 31, 2003
9. Henry R. Lawrie, FCA - March 19, 2003
10. Nexen Inc. - March 31, 2003
11. OMERS - March 31, 2003
12. Petro-Canada - March 27, 2003
13. Society of Petroleum Evaluation Engineers (Calgary Chapter) - March 28, 2003
14. Standard Life Investments - March 20, 2003
15. Prospectors & Developers Association of Canada - March 24, 2003
16. Toronto Stock Exchange and TSX Venture Exchange - March 31, 2003
Comments were provided by a range of participants in the capital markets and the oil and gas industry: institutional investors, oil and gas producing issuers, reserves evaluation firms and associations, individual professionals and exchanges. Nine commenters had previously commented on the first version of the Instrument that was published on January 25, 2002 (the “2002 Proposal”).
The CSA thank the commenters. We appreciate their time and effort. We have considered carefully each of the commenter’s suggestions or views.
Commenters were generally supportive of the key principles of the Instrument. A number of commenters stated that the 2003 Proposal was easier to follow and believed that it met the needs of the CSA, investors and industry better than the 2002 Proposal. One senior producer said that the Instrument “will improve overall disclosure while at the same time recognizing the oil and gas industry's need to maintain effective cross-border financial activity”, and urged the CSA to implement the Instrument as soon as practicable so that industry could respond in a timely and appropriate manner to the new requirements.
The most frequently mentioned areas of concerns were:
- the scope and application of the discretionary exemptions set out sections 8.2 and 8.4 of the Companion Policy; and
- the level of detail required by certain Items of Form 51-101F1 (“Form1”).
We have adopted a number of technical comments and suggestions. Other comments and our responses are summarized below, grouped by subject matter as follows:
- terminology and application of the Instrument;
- specific provisions of the Instrument;
- the four issues on which we had invited comment in the 2003 Proposal; and
- matters of general application.
1. Terminology and Application of the Instrument
(a) Application to Non-Conventional Activities
Two commenters suggested that conventionally mined oil sands should be dealt with as mineral projects under National Instrument 43-101 Standards of Disclosure for Mineral Projects (“NI 43-101”) and excluded from NI 51-101, and that NI 51-101 should make clearer whether it deals with either or both coal or coal bed methane. One commenter noted that a CIM committee is considering whether to propose the inclusion in NI 43-101 of new definitions relating to oil sands similar to those used for mineral projects.
The intended product of both conventional and non-conventional oil projects is essentially the same - a liquid hydrocarbon. We believe that investors are likely to consider a reporting issuer focused on oil sands to be more comparable to a conventional oil producer than to a hard rock mining issuer. Accordingly, NI 51-101 applies to activities directed at the extraction or production of hydrocarbons from either conventional or non-conventional sources (such as surface mines and in situ projects).
We believe that the definition of “oil and gas activities” makes clear that such activities include the search for and extraction of hydrocarbons and by-products, which would include coal bed methane (a hydrocarbon) but not coal.
We recognize that the process of mining oil sands differs from conventional oil production from wells, and has similarities to other mineral projects. As discussed in section 1.6 of the Companion Policy, oil sands mining issuers may find useful guidance in NI 43-101 concerning disclosure about mine development and operation that could supplement their disclosure of reserves data and other information under NI 51-101.
There may be circumstances in which a reporting issuer’s non-conventional oil and gas activities also involve exploration, development or production activities in respect of non-hydrocarbon minerals, such as coal. If those non-hydrocarbon activities are also material to the reporting issuer, that aspect of its business is likely to be subject to the disclosure standards under NI 43-101, while the oil and gas activities remain subject to NI 51-101.
In the event that market and industry participants and professionals active in the oil sands or other non-conventional oil and gas sectors develop new definitions for those sectors, the CSA will consider whether the Instrument should be modified or supplemented.
(b) Interaction with the COGE Handbook
One commenter noted that some of the terms identified in the Glossary (Appendix 1 to the Companion Policy) as deriving from the COGE Handbook do not appear in the glossary in the COGE Handbook. More generally, the commenter urged that effort be made to conform the COGE Handbook to the Instrument and eliminate any contradictions.
The Glossary is meant to assist users by directing them to original source documents, if any, for definitive or expanded explanation in a glossary or in the body of the source document. We have modified slightly some of the definitions in the Glossary to match the corresponding discussion in the COGE Handbook.
(c) Contractual Prices
Two commenters suggested that we clarify that the contractually fixed prices used in determining both “constant prices and costs” and “forecast prices and costs” exclude contracts that are, for accounting purposes, “financial instruments” or “financial hedges”.
We have revised the definitions to clarify that contractual prices are used if the reporting issuer is obligated to supply a physical product (typically, oil or gas). If the reporting issuer can satisfy its obligation in cash rather than by supplying physical product, the contractual prices are not used for this purpose. In that case, as new section 4.3 of the Companion Policy explains, the obligation may be a “financial instrument” for which the CICA Handbook discusses financial statement disclosure.
(d) Qualified Evaluators and Auditors/Qualified Persons
One commenter suggested that NI 51-101 use the NI 43-101 term “qualified person” instead of the two terms “qualified reserves evaluator” and “qualified reserves auditor”.
NI 51-101 and NI 43-101 were developed for different industries. NI 51-101 (and the COGE Handbook) deliberately distinguish between the reserves evaluation and reserves audit functions.
(e) Supporting Filing
One commenter questioned the deletion, from the definition of “supporting filing”, of the proviso that post-filing events have not rendered the document inaccurate or misleading.
We had deleted this proviso because it could have been interpreted as creating a requirement to update original filings. With or without the proviso, reporting issuers are responsible for ensuring that their disclosure record as a whole is not misleading.
2. Specific Provisions of NI 51-101
(a) Part 3 - Directors
An institutional investor expressed a wish that each board of directors establish a reserves review committee that has two or three independent members with background or experience in reserves evaluation.
The CSA encourage the formation of reserves committees, which are discussed in Section 3.5 of NI 51-101. The Instrument does not prescribe particular background or experience for board or reserves committee membership. We expect that shareholders and directors will give due attention to the background and experience appropriate for members of their company's board or reserves committee.
(b) Part 4 - Measurement
(i) Subsection 4.2(1) - Requirements for Disclosed Reserves Data
One commenter stated that paragraph 4.2(1)(d) of NI 51-101 is hard to follow and seems to mix two issues.
We have reorganized subsection 4.2(1) to make it clearer:
- Paragraph (a) specifies conditions that apply in general to filed reserves and future net revenue estimates: qualification of the preparer of the estimates, adherence to the COGE Handbook, and assumption that development funding will be available.
- Paragraph (b) (formerly paragraph (d)) requires that abandonment and reclamation costs be considered before attributing reserves to an undrilled property.
- Paragraph (c) (formerly paragraph (e)) requires that future net revenue estimates include deductions of future well abandonment costs (see the following comment) and, unless otherwise specified in the Instrument, future income tax expenses.
(ii) Future Net Revenue and Abandonment and Reclamation Costs
One commenter asked that we define “abandonment and reclamation costs” and “salvage value”. Some commenters expressed uncertainty as to whether total abandonment and reclamation costs are to be considered by the reserves evaluator in estimating future net revenue (disclosed under Part 2 of Form 1) or only by the reporting issuer in its additional disclosure (Part 6 of Form 1). The commenters noted that reclamation costs, and salvage value, cannot be accurately estimated by evaluators without site visits and formal evaluation by experts in that area.
We have made clarifying changes. We did not define “abandonment and reclamation” and “salvage value”. Instead, the newly-defined term “well abandonment costs” (that subset of total abandonment and reclamation costs relating specifically to the cost of abandoning a well and disconnecting it from the surface gathering system) is used in place of former references to total abandonment and reclamation costs in:
- the definition of “future net revenue”;
- paragraph 4.2(1)(c) (formerly paragraph 4.2(1)(e)) of NI 51-101 concerning the estimation of future net revenue; and
- Part 2 of Form 1, where new Instruction 3 explains that the abandonment and reclamation costs deducted in the estimation of future net revenue must include, at minimum, well abandonment costs.
Whether or not the reserves evaluator considers more than well abandonment costs in estimating future net revenue, Item 6.4 of Form 1 requires that the reporting issuer (not the evaluator) disclose its total abandonment and reclamation costs (for surface leases, wells, facilities and pipelines) and state what portion, if any, of that total is not already reflected in the reserves data.
(c) Part 5 - All Disclosure
(i) Section 5.3
One commenter questioned whether section 5.3 of NI 51-101 should be expressly subject to section 1.2.
Section 5.3 is not subject to section 1.2. Section 1.2 applies only in the case of conflicting definitions of the same term in (i) NI 51-101 or other securities legislation, and (ii) the COGE Handbook. Section 5.3 requires, in effect, that disclosure of reserves use the COGE Handbook reserves definitions. The COGE Handbook reserves definitions therefore prevail (they are repeated in the Glossary simply for ease of reference).
(ii) Disclosure of Natural Gas
One commenter suggested that volumetric description of natural gas does not reflect its value and that quantities of natural gas should instead be reported on the basis of standard heat content, gigajoules or MMBtus. The commenter also questioned the requirement in section 5.4 for disclosure of marketable quantities reflecting prices for natural gas in the condition in which it is sold, suggesting that producers may not know the eventual condition of gas sold, in their name, outside Alberta.
We have not adopted the comments. The CSA’s objective is to ensure consistency and reliability in the disclosure of information that capital markets are accustomed to. The commenter raises interesting points but we believe that it would exceed the purpose of the Instrument to impose, without thorough industry and public debate, this change in what we understand to be widespread industry usage. The commenter might wish to pursue with petroleum industry associations these ideas for a change in industry practice.
Section 5.4 emphasizes consistency of disclosure concerning products in their saleable rather than raw condition. Reporting issuers should interpret the provision reasonably in this light.
(iii) Paragraph 5.8(b) - Disclosure for all Properties
One commenter criticized, as excessively onerous, the requirement under paragraph 5.8(b) to supplement any disclosure of property-specific reserves with disclosure of total reserves for all properties. The commenter suggested that, when it applies, the provision could be satisfied using earlier reserves data updated only for production.
We do not consider the provision onerous. It is meant to ensure that disclosure by a reporting issuer of estimates for a particular property does not mislead readers in light of the different confidence levels that might apply to a single property as compared to estimates for the reporting issuer as a whole, owing to the effects of aggregation. We do not prescribe any particular computations or adjustments. As with all public disclosure, a reporting issuer is responsible for taking the steps necessary in the circumstances to ensure that its disclosure is not misleading.
Two commenters requested clarification about what is meant by anticipated results from prospects.
Section 5.9 is meant to give investors specific information to add context to a reporting issuer's disclosure of its expectations for an oil and gas play not yet beyond the exploration stage. The CSA consider such contextual information particularly important where the disclosure suggests actual volumes or cash flows. We have made no substantive change to section 5.9 (or to section 5.10 which deals with disclosure of the fair value of a prospect).
(d) Part 6 - Material Changes
One commenter expressed concern about the costs of having an independent reserves estimate prepared whenever a reporting issuer reports a material change.
The comment suggests a misunderstanding of Part 6 of NI 51-101. If a material change report is triggered, and if the triggering event would affect reserve estimates, Part 6 requires that the material change report comment on the effect of that material change on the most recent NI 51-101 annual filing. Part 6 does not mandate any particular procedure, the involvement of an independent evaluator for that purpose, or the filing of another formal evaluation report. It is the responsibility of the reporting issuer to consider what steps are necessary in the circumstances to ensure that its disclosure is not misleading.
3. Specific Provisions of Form 51-101F1
(a) Part 1 - Date of Statement
One commenter questioned the removal of the discussion, found in the Instructions to Part 1 of Form 1 in the 2002 Proposal, concerning information arising between the effective date and the preparation date of an evaluation report.
Our primary objective is to ensure that all professionals involved in a reserves evaluation communicate with each other and the reporting issuer to ensure that the reporting issuer’s disclosure is complete and consistent. We considered that portion of the Instructions overly prescriptive and unnecessary for this purpose.
(b) Part 2 - Disclosure of Reserves Data
A number of commenters expressed the view that some of the prescribed disclosure of reserves data was more detailed than necessary to serve investor needs. One commenter suggested that some of the detail is proprietary.
We understand that the commenters’ concerns relate primarily to the breakdowns of future net revenue required under Items 2.1(3) and 2.2(3) of Form 1.
The CSA agree that mandatory public disclosure of some of the detail, such as breakdowns of future net revenue components year-by-year for ten years, would be unnecessary. We believe that we have addressed the commenters’ concerns by revising Items 2.1(3) and 2.2(3) to require only the totals (not year-by-year for ten years) for each component of future net revenue. The disclosure of forecast prices and future development costs has also been reduced from ten years to five (for development costs, this requirement now appears in Item 5.3).
(c) Part 4 - Reconciliations
(i) Constant Case/Forecast Case
The 2003 Proposal would give reporting issuers the choice of using either constant or forecast prices and costs in their reconciliations of reserves and future net revenue. A number of commenters urged that the Instrument mandate one price and cost case for the reconciliations (one urging the forecast case, another the constant case, and a third not specifying) to facilitate comparability among reporting issuers.
We have not made this change. The CSA expect reconciliations to be used more to track the performance of a reporting issuer and the reliability of its reserves data estimates from one year to the next, than for item-by-item comparisons between companies. This makes a universally mandated set of assumptions less critical than for some of the reserves data disclosure itself.
Item 4.1 of Form 1 requires reconciliations of reserves for each of the proved, probable and proved plus probable categories. To prepare the reconciliation the reporting issuer will need reserves estimates for each of those categories. Were Item 4.1 to mandate constant case reconciliations, the reporting issuer would have to prepare constant case reserves estimates in the probable and proved plus probable categories, which are deliberately not mandated under Part 2 of Form 1. On the other hand, we understand that forecast case reconciliations can be more difficult to prepare and, as evidenced by one of the comment letters, they may not satisfy all users. Rather than impose either choice, we think it sufficient that a reporting issuer discloses which price and cost case it is using.
(ii) Need for Future Net Revenue Reconciliation
One commenter suggested deleting the reconciliation of future net revenue on the grounds that it is not meaningful, is tedious to put together (requiring a joint effort between evaluators and accountants) and may take more time than is available.
We have retained the requirement. We acknowledge that future net revenue reconciliations require effort, but we also understand that some market participants consider them important. They are required under US FASB standards and were recommended by the ASC oil and gas taskforce.
(iii) Gross Reserves/Net Reserves
One commenter recommended that reconciliations be made using company gross reserves, not company net reserves, because royalties are sensitive to price fluctuations.
Although royalties may add a degree of complexity to preparing reconciliations, the CSA consider company net reserves (called “net reserves” in the Instrument) the correct choice because they better reflect a reporting issuer's true reserves position (by including royalties owned by the reporting issuer and excluding royalties owned by others).
(iv) Economic Factors
One commenter suggested that we delete the reconciliation item “economic factors” because it requires the additional step of rerunning the earlier data with the most recent year-end price and cost case, is expensive and time-consuming and provides insignificant results.
We have retained this item. The rerun would only be required if the prior year's estimates are revised as a result of changes in previously-estimated prices and costs and only if this revision is material.
(v) Property Disposition or Acquisition
One commenter sought clarity as to whether the effect of a disposition or acquisition on the aggregation process is to be reported as a “technical revision”.
We infer from the question that the commenter is distinguishing between
(i) the estimated reserves or future net revenue attributed to a property acquired or disposed of, considered in isolation, and
(ii) the incremental effect that the acquisition or disposition of that property could have on the estimates for the reporting issuer as a whole, because of aggregation.
We would ordinarily expect the full effect to be disclosed in the reconciliation as a “disposition” or “acquisition”, and not as a technical revision. A reporting issuer may, however, wish to provide additional explanation to make the reconciliation understandable and meaningful.
(d) Part 5 - Additional Information Relating to Reserves Data
One commenter suggested that we require disclosure of the capital requirement pertaining to the transfer of proven non-producing reserves to the proven producing category.
The disclosure required by Item 5.3 about development costs - estimated amounts in total and by year for the first five years, and a discussion of the source and funding of such costs - should address what we understand to be the commenter’s concern.
(e) Part 6 - Other Oil and Gas Information
One commenter suggested that detailed disclosure required by Item 6.3 concerning forward contracts would be in direct violation of confidentiality provisions contained in most gas purchase and sale contracts. The commenter suggested that the CSA restrict the disclosure requirements to fundamentals that enable the reader to understand a reporting issuer’s marketing portfolio: contract term, nature of buyer, market location and basic pricing structure.
Item 6.3 is intended to inform investors if a reporting issuer cannot benefit from favourable market prices because it has by contract locked in future sales at pre-determined prices. We have clarified that a general discussion of key aspects of such a contract will suffice.
4. Form 51-101F2
(a) Future Net Revenue
One commenter requested that we clarify whether the estimated future net revenue to be stated in Item 4 of Form 51-101F2 (“Form 2”) is calculated before or after deduction of income taxes.
We have revised Item 4 to clarify that the amount is future net revenue before deduction of income taxes.
One commenter suggested that the CSA differentiate between factual statements and reservations and provide a clearer explanation of what constitutes a reservation or disclaimer. For example:
- Did a site inspection take place? (The commenter noted that for some foreign properties a site visit by the evaluator might be prudent.)
- Have multiple evaluators used a common set of assumptions regarding product pricing, inflation, and exchange rates?
The explanation of the term “reservation” set out in the Glossary reflects the CSA’s intention. We believe that material departures from the wording of Form 2, or from the standards set out in the COGE Handbook, impair the comparability of disclosure.
Concerning the specific example cited by the commenter, if a site visit is appropriate under COGE Handbook standards and its absence would be a material departure from good evaluation practice, then we would regard the absence of a site visit as inappropriate and a reference to that fact as an impermissible reservation. In the case of foreign properties, the CSA agree with the commenter that site visits would be prudent.
The Instrument does not specify how the work of multiple consultants will be coordinated or compiled. The responsibility for the disclosure is that of the reporting issuer, whether it engages one or several evaluators. We believe that the arrangements between the reporting issuer and its evaluators to ensure the required quality of the disclosure are best left to their corporate and professional judgement.
One commenter requested that evaluators be allowed greater flexibility with regard to disclaimers (or reservations) on prospects.
The CSA do not believe that evaluators need greater flexibility concerning prospects. Disclosure concerning prospects is not part of the mandatory reserves data on which the evaluator reports in Form 2. If a reporting issuer chooses to make disclosure concerning prospects, it is the reporting issuer's responsibility to ensure that it satisfies Part 5 of NI 51-101.
(c) Consent Letters
Two commenters suggested that the Instrument was not clear as to when consent letters from evaluators are or are not required, or as to why no consent is required for a reporting issuer to file the evaluator’s report (Form 2) or issue the news release required by section 2.2 of NI 51-101.
The CSA believe that the evaluator's consent to the reporting issuer's use of the evaluator's report (Form 2) is implicit. An evaluator should anticipate, when it gives its client issuer a signed Form 2, that the purpose is to enable the reporting issuer to satisfy its obligations under the Instrument by filing the report and issuing the news release. However, written consent from the evaluator is required if the reporting issuer uses the reserves data to which the Form 2 relates for other purposes, such as in a subsequent news release or in a securities offering document.
5. Form 51-101F3
One commenter stated that certification of Form 51-101F3 (“Form 3”) by two senior officers and two directors exposes them to a higher level of liability than exists in other Canadian industries and limits the defences available to them. Another commenter urged that we make clearer in Form 3 the differing responsibilities of management and directors.
Form 3 is meant to confirm for readers the respective roles of management and directors and the process underlying corporate oil and gas disclosure. We believe that it does so. We are not persuaded that it exposes officers and directors to excessive or inappropriate liability or denies them appropriate defences. To the extent that civil liability arises under securities legislation, the relevant provisions also set out available defences. The CSA remain of the view that Form 3 will enhance market confidence in oil and gas disclosure and thereby indirectly serve the interests of reporting issuers too.
6. Companion Policy: Possible Discretionary Exemptions
Commenters expressed strong, but opposing, views on the possible discretionary relief discussed in Part 8 of the Companion Policy. The focus was on two provisions:
- section 8.2, which discusses possible discretionary exemption to permit a senior producing issuer to use in-house, rather than independent, evaluators; and
- section 8.4, which discusses possible discretionary exemption to permit a reporting issuer that files disclosure in both Canada and the US to present oil and gas information more in accordance with US practice.
While some commenters were opposed to some or all such discretionary relief, proponents from among the class of issuers that might be eligible for relief stressed in their comments that such discretionary relief would be extremely important. One such issuer characterized the suggested relief as “absolutely crucial”.
(a) Relief from Independent Evaluation or Audit Requirement
(i) General Principle and Scope
Opponents of the possible discretionary relief discussed in section 8.2 of the Companion Policy felt that all reporting issuers, irrespective of size, should have annual independent reserves evaluations or audits. They argued that:
- exemption would be inconsistent with the trend toward improved corporate governance;
- the availability of reserves audits as an alternative to reserves evaluations would reduce the cost burden of independent involvement; and
- tying exemption to the size of the reporting issuer is misguided, size being no assurance of good disclosure.
Comments of some of the larger issuers indicated that such relief was appropriate and important to them. Proponents generally supported the relief on grounds of cost. Larger issuers pointed to their well-established internal capabilities, and checks and balances, that would ensure the quality of their internally-generated reserves estimates.
Two commenters suggested that similar relief ought also to be available to small issuers, one suggesting that the relief would be more appropriate for the smallest issuers than for the largest. It was argued that independent evaluations would be proportionately more costly for smaller issuers but “not sufficiently change the risk profile inherent in an emerging issuer's reserves estimates”.
The CSA remain of the view that the terms and conditions of the discretionary relief discussed in section 8.2 are appropriate. We have made no substantive change to the provision.
We continue to place considerable importance on independent involvement in reserves disclosure, as a method of ensuring quality and as an important element of sustaining market confidence. It is our understanding that the great majority of public companies of all sizes already engage independent evaluators to satisfy the demands of their lenders, investors, auditors or directors.
We acknowledge that the costs of independent evaluation may, as a proportion of market capitalization or other measure of size, be relatively greater for smaller issuers than for larger issuers. It is our view that the benefits of independent involvement, too, may be relatively greater. In some cases, only an independent evaluator might have the resources needed to evaluate a smaller issuer's reserves. We also believe that greater market confidence in the oil and gas sector as a whole, consequent on implementation of the Instrument, is likely to be of direct benefit to both smaller and larger issuers seeking capital.
For these reasons, the CSA are not at present prepared to relax that requirement for smaller issuers. We do anticipate that the possibility of modified treatment for the most junior issuers may be considered in connection with the CSA's separate initiative investigating the merits of “proportionate regulation”.
For senior producers, the relief contemplated in section 8.2 would in effect maintain the current position reflected in ASC Staff Notice 43-701 (December 1, 2000), which restricts exemption from the independent evaluation requirement under NP 2-B to that class of issuer. The discussion in the Companion Policy, however, is more restrictive in that it suggests that the relief would likely be conditional on the applicant demonstrating satisfactory in-house evaluation capabilities and disclosure practices. Other aspects of NI 51-101 would continue to apply to holders of such an exemption: the evaluator, in-house or independent, must have the qualifications and experience called for in the Instrument and the COGE Handbook, and apply the reserves evaluations procedures set out in the COGE Handbook. The role and responsibilities of issuer management and directors are little affected by such relief, and their (modified) report would still be filed. Whether or not a reporting issuer relies on such an exemption, its disclosure and underlying reserves evaluation may be reviewed by securities regulatory staff as part of a continuous disclosure review.
We expect (as one commenter noted in its letter) that even reporting issuers that might be eligible for such relief may decide to engage independent evaluators to satisfy other external requirements or as a measure of internal quality assurance.
(ii) Unconditional Exemption?
One commenter expressed concern that exemption from the independent evaluation requirement would not be subject to any particular conditions, and suggested that allowing the exemption at the reporting issuer's sole discretion could leave room for potential abuse.
The exemption would not be at the reporting issuer's sole discretion. The discretion is that of the securities regulatory authority. As discussed above and in section 8.2, relief would likely be subject to important conditions including regulatory satisfaction with the applicant's reserves evaluation capabilities and disclosure practices and undertakings by the applicant.
(iii) Text of Modified Report
One commenter noted that the wording of the representation concerning management influence on evaluators set out in a modified Report of Management and Directors on Reserves Data and Other Information was problematic.
We agree with the commenter. The text has been revised to refer to the likelihood of the in-house evaluator's work being adversely influenced.
(iv) Small Issuer Reliance on Senior Producer's In-House Evaluation
One commenter asked whether a small issuer's independent evaluator could use reserves estimates prepared by a senior issuer's in-house evaluators, without further audit.
We think it unlikely that a qualified reserves auditor would be prepared to issue a report based on bare reliance on the report of another. However, the concept of audit does imply the exercise of judgement as to the extent of review and investigation appropriate in respect of reserves information prepared by another. The extent to which a qualified reserves evaluator or auditor is able or willing to rely on evaluation work of another will likely vary with the circumstances of each case, audit standards set out in the COGE Handbook and applicable professional standards of practice and codes of ethics.
(b) Discretionary Relief to Permit US-Style Disclosure
The contemplated discretionary relief to permit cross-border reporting issuers to disclose oil and gas information more in accordance with US practice was criticized by both proponents and opponents:
- Some cross-border reporting issuers urged that the exemption be automatic, and that it should go further by treating US Form 10-K disclosure as a complete substitute for NI 51-101 (implying that disclosure of the terminology and standards used, explanation of major differences from NI 51-101 standards, and accompanying reports of the evaluator and management and directors, should be waived).
- One commenter requested that Canadian disclosure required despite the exemption, but not mandated by the SEC, should be accepted in a filing separate from the Form10-K or AIF.
- Some commenters feared that disclosure beyond that required by the SEC but, we understand, routinely provided in other US public disclosure (such as disclosure of probable reserves) would jeopardize their exemption.
- One commenter objected to the potential for reporting issuers to “cherry-pick” the disclosure requirements of NI 51-101, choosing those it likes and ignoring the others. The commenter argued that allowing reporting issuers to disclose probable reserves without disclosing the related future net revenue seems to encourage misleading disclosure and does not facilitate comparisons.
The CSA are persuaded that, for reporting issuers heavily engaged in the US capital markets, mandatory disclosure under two sets of disclosure standards and practices could be both costly to the reporting issuers and confusing to investors. We believe that there will be appropriate cases to permit such reporting issuers to provide oil and gas information in a manner more consistent with US practice. The discretionary nature of the relief gives regulatory staff an opportunity to consider each applicant's case. The undertakings and conditions contemplated in section 8.4 - including public disclosure of how a reporting issuer's disclosure differs from NI 51-101, and the provision of comparable information from year to year - should enable Canadian investors to use that information to make informed investment decisions and to make comparisons with other Canadian issuers.
Contrary to the interpretation of some commenters, voluntary disclosure beyond that required in the US (for example, probable reserves estimates), if consistent with the undertakings and conditions discussed in section 8.4, would not jeopardize the exemption.
The Instrument offers flexibility in its presentation of the required disclosure. The CSA do not consider an unmodified Form 10-K filing alone sufficient. We believe that Forms 2 and 3 provide important information that is not necessarily available in Form 10-K. We consider explanations of material departures from NI 51-101 essential for Canadian investors, but we have modified the discussion in 8.4 to suggest that such disclosure can be “reasonably proximate” to the primary disclosure in a Form 10-K (for example, in a Canadian “wrapper”).
Reporting issuers would not be completely free to “cherry-pick” the disclosure they prefer from one year to the next. Paragraph 8.4(b)(iii) indicates that an exemption would be subject to conditions designed to ensure that the disclosure applies clearly identified standards and definitions, that key assumptions are stated, and that the information disclosed in one year (if the subject remains material for the reporting issuer) continues to be provided in subsequent annual filings so that investors can assess and compare that information from year to year.
(c) Annual Reapplications?
One commenter suggested that discretionary relief under the Instrument should be time-limited, and that applicants ought to reapply each year to extend the relief.
The CSA believe that the suggestion would add an administrative burden for both applicant and regulator that outweighs the benefit to the public. Discretionary relief is only granted on terms and conditions considered appropriate in the circumstances. Thereafter the reporting issuer, like any other, must comply with securities legislation and the terms and conditions of its own exemption.
7. Responses to CSA Questions
The CSA Notice that accompanied the 2003 Proposal sought public comment on four issues. The following discussion summarizes the questions we asked, the public comments received and our responses.
(a) Effect of Conversion to CIM Reserves Definitions
(i) Might there be a widespread and substantive difference between proved reserves estimated using the CIM definitions as compared to estimates made reasonably applying the NP 2-B definitions?
(ii) Market participants (reporting issuers, analysts, investors, creditors) will need to become aware of and understand the new CIM definitions and the extent to which reported estimates can be expected to differ from those under NP 2-B. How can the CSA help foster market awareness and understanding of the new CIM reserves definitions?
The widely varying responses to our queries indicate a considerable diversity of view as to how the conversion to the CIM definitions will affect evaluation results. There does, however, seem to be general support for using the industry-developed definitions.
A number of commenters encouraged education of users through seminars to facilitate the transition to the new reserves definitions. One commenter did not think that most investors would ever grasp the meaning of the definitions and should not be expected to; the commenter suggested instead that disclosure should emphasize that reserves are an estimate with a range of possible actual outcomes.
We are persuaded from the comments that it would be at best premature, and likely impossible, to make any general statement as to how estimates under the new definitions are likely to compare to the disclosure under NP 2-B, either systemically or issuer by issuer. We believe that investors can understand even technical information if it is well presented and we agree that good corporate disclosure should convey clearly that reserves estimates are just that - estimates reflecting varying degrees of certainty. The CSA will consider means of fostering awareness of the changes and we encourage market participants to do the same.
(b) Mandatory Disclosure of “Constant Case” Reserves Data
Should the CSA reconsider the requirement in the Instrument for disclosure of constant case estimates of proved reserves and related future net revenue? In particular:
(i) Are such estimates sufficiently important to investors to warrant mandatory disclosure?
(ii) Would the response to question (i) differ if the “ceiling test” in the CICA Handbook's Accounting Guideline AcG-5 were modified to no longer use a constant case estimate of future net revenue?
The majority of commenters stated that reporting of the constant case was useful for comparability and consistency. One commenter urged mandatory disclosure of constant case estimates of both proved and probable reserves using the same range of discount rates as for the forecast case.
We are persuaded by the majority of commenters that it is worth retaining the requirement for some constant case disclosure. The Instrument therefore continues to require disclosure of reserves data estimated using both the forecast case and the constant case. Reporting issuers are free to match the same level of detail in their constant case disclosure as in their forecast case disclosure, but we do not think it necessary to make it mandatory.
(c) Professional Organizations
We sought comment on the criteria set out in the definition of “professional organization”, membership in which is a condition of being a “qualified reserves evaluator or auditor”.
Senior issuers generally supported the CSA’s approach to evaluating Canadian and foreign professional organizations as set out in section 1.5 of the Companion Policy. They encouraged the CSA to “pre-clear” large internationally recognized foreign reserves evaluators prior to implementation.
We have made no substantive changes to section 1.5. We will consider applications for exemption from the Canadian professional membership requirement as contemplated in that section, including applications submitted before the effective date of the Instrument. In considering such applications, evidence of the views of a Canadian professional organization as to the equivalency of particular foreign standards to Canadian standards would likely be helpful.
(d) Disclosure by Product Type/Production Group
Would it be preferable to prescribe certain reserves data disclosure for “production groups” (the aggregate of products derived from a single well or reservoir) rather than separately for each product type?
Some commenters suggested that reserves volumes and sales prices be reported by product type and that the related future net revenue be reported by production group. Two commenters suggested that distinguishing between product types, and combining single product types from different operations, is a subjective exercise: one referred to “artificial splits” and another to “fictional combinations”. One commenter criticized the increase in the number of product types to nine from the four specified in the 2002 Proposal.
We agree with the commenters that allocating costs among product types within a production group to estimate future net revenue can be problematic. The Instrument now specifies that reserves estimates are to be disclosed by product type and the related future net revenue by production group.
Most of the increase in the number of product types involved non-conventional products. We have retained those product types; a reporting issuer does not have to report product types that are not material to it. We had added, but have now removed, “sulphur and other non-hydrocarbon by-products” as a separate product type.
8. Matters of General Application
(a) Extend the Comment Period?
One commenter suggested that the period for public comment be extended, in light of the number of changes from the 2002 Proposal and the fact that the comment period coincided with a busy time for some analysts and consultants.
The commenter noted that the public consultation process has already lasted over two years. In fact, the Instrument responded to the ASC oil and gas taskforce recommendations and the CIM reserves definitions, both of which were themselves the result of several years of debate and consultation.
Some commenters urged, and the CSA agree, that it is now time to bring the Instrument into effect, and that we should do so promptly so that industry and its advisors have time to prepare for compliance. Accordingly, we did not extend the comment period.
(b) The Documents
One commenter was critical of the length of the Instrument and specifically questioned the placement of some of the requirements in forms rather than in NI 51-101. The commenter suggested that each provision in the Companion Policy bear the same number as the corresponding provision in NI 51-101, even if gaps in the numbering result.
We have endeavoured to balance the desire for brevity with the need to provide certainty and guidance. Each of the three forms included in the Instrument consolidates the detailed requirements of most direct relevance to a particular user group: the issuer; the reserves evaluator and auditor; and management and directors. Use of the form has also allowed us to include instructions designed to assist those users. The purpose of CSA companion policies is to explain and provide guidance on mandatory elements in rules and forms, including discussion of how securities regulatory authorities are likely to interpret and apply specific provisions. Some provisions of the Companion Policy pertain to more than one provision (and more than one document), making the direct matching of provision numbers impractical.
(c) Establish a Multidisciplinary Advisory Committee
One commenter suggested that the CSA set up a multidisciplinary advisory committee.
The CSA see merit in establishing a multidisciplinary advisory committee with industry and professional participation to advise on application of the Instrument, developments in industry and emerging issues. A similar body has proved very helpful in connection with NI 43-101. We will consider the suggestion further.
Advance Notice of National Instrument 51-101
Standards of Disclosure for Oil and Gas Activities and Related Documents
Summary of Changes from the 2003 Proposal
The following discussion summarizes differences between National Instrument 51-101 (“NI 51-101”) and its related Forms and Companion Policy (together, the “Instrument”) published for comment on January 24 (on March 21 in Québec), 2003 (the “2003 Proposal”).
The Instrument is consistent in substance with the 2003 Proposal, but it does incorporate limited changes.
Most of the changes are intended to clarify the application of the Instrument. A number of the changes were made in response to specific comments or suggestions made by public commenters.
Partly in response to more general comments received, we have also revised certain of the specific disclosure requirements in Form 51-101F1 (“Form 1”) with a view to streamlining the disclosure while making it more meaningful to investors.
The Instrument incorporates a limited number of new or modified definitions or interpretations, in either or both Part 1 of NI 51-101 and Appendix 1 to the Companion Policy.
(i) Price and Cost Assumptions - Contract Prices
We amended the definitions of “constant prices and costs” and “forecast prices and costs” to clarify the circumstances in which contractual prices are to be used in estimating reserves data.
The revision to the definitions makes clear that contract prices are to be used for both the constant case and forecast case estimates if the contract or other obligation binds the reporting issuer to supply a physical product (typically, oil or gas). If the reporting issuer is able to satisfy its obligation in cash rather than by supplying physical product, the contractual prices are not used for this purpose. In that case, the obligation may be a “financial instrument” for which, as new section 4.3 of the Companion Policy explains, the CICA Handbook discusses financial statement disclosure.
(ii) Future Income Tax Expenses
The 2003 Proposal defined the term “future income tax expenses” but used the defined term interchangeably with the undefined term “income taxes”. The Instrument now uses the defined term except where the more generic term is used in a document likely to be read by the general public.
(iii) Future Net Revenue
The definition of “future net revenue” is amended to eliminate an inconsistency with the way the term is applied in some provisions of the Instrument. The revised definition:
- prescribes the deduction of “well abandonment costs” (a newly-defined term) rather than total abandonment and reclamation costs (see the discussion below under “Abandonment and Reclamation Costs”); and
- contemplates exceptions to the general principle that future income tax expenses are deducted in estimating future net revenue (there are several instances in which the Instrument refers specifically to “future net revenue before deducting future income tax expenses”).
(iv) Product Types
The 2003 Proposal defined “product type” to include, among other things, natural gas and two types of oil and gas by-products: (i) natural gas liquids and (ii) sulphur and other non-hydrocarbon compounds.
Because natural gas can include natural gas liquids, listing them as separate product types created an inconsistency or overlap. To address that problem, to resolve other potential ambiguities and to facilitate other disclosure changes discussed below, the Instrument now:
- expands the definition of “gas” to refer to “associated gas”, “non-associated gas”, and “solution gas”, and defines each;
- makes clear that the term “crude oil” does not include solution gas (natural gas dissolved in oil);
- defines “natural gas liquids”; and
- makes clear, in the definition of “product type”, that natural gas liquids are a separate product type, not a part of “natural gas”; and
- eliminates sulphur and other non-hydrocarbon products as a product type.
(v) Production Group
The new term “production group” (a concept applied indirectly in certain provisions of the 2003 Proposal) groups the principal product type from a well or reservoir with its by-products.
Use of the concept in certain revised disclosure requirements (see below under “Disclosure by production groups”) avoids the need for arbitrary and potentially misleading allocations of costs and other factors among multiple products that are produced together from a well or reservoir. This should make disclosure both simpler and more meaningful.
(vi) Proved and Unproved Properties
The 2003 Proposal's definitions of “proved property” and “unproved property” left an unintended gap between properties to which proved reserves are attributed and properties to which no reserves of any category have been attributed. To close the gap, the definition of “proved property” has been amended to refer to a property to which reserves of any category have been attributed.
The Instrument now uses these defined terms instead of more general descriptions of the same concepts that had been used in certain provisions of the 2003 Proposal (for example, in Item 6.2 of Form 1).
(vii) Conformity to CICA Handbook
Minor additions or modifications have been made to the definitions of “exploration costs”, “exploratory well” and “property” for conformity with the corresponding definitions in Accounting Guideline AcG-5 “Full cost accounting in the oil and gas industry” in the CICA Handbook.
(b) Estimating and Disclosing Reserves Data
(i) Abandonment and Reclamation Costs
The CSA consider estimated “abandonment and reclamation costs” a very important element of oil and gas disclosure. The quoted phrase, however, covers a variety of costs, not all of which will necessarily be known to, or taken into account by, a qualified reserves evaluator or auditor in estimating reserves data. In many cases, the qualified reserves evaluator or auditor may take into account only a subset of total abandonment and reclamation costs - “well abandonment costs” - (costs of abandoning a well and disconnecting it from the surface gathering system), in estimating future net revenue.
As it did in the 2003 Proposal, Item 6.4 of Form 1 continues to require a reporting issuer to disclose its estimated total abandonment and reclamation costs and (under paragraph 6.4(d)) to disclose the portion of those amounts that have not been deducted in the disclosed estimates of future net revenue on which the qualified reserves evaluator or auditor reports.
Certain provisions of the 2003 Proposal, however, seemed to suggest that the reserves data must invariably be estimated taking into account all abandonment and reclamation costs, a result clearly inconsistent with Item 6.4(d).
To address this inconsistency, the Instrument now uses the newly-defined term “well abandonment costs” in:
- paragraph 4.2(1)(c) (formerly paragraph 4.2(1)(e)) of NI 51-101, which sets out as a general requirement for disclosed reserves data that well abandonment costs (not necessarily total abandonment and reclamation costs) must be deducted in estimating future net revenue; and
- new Instruction 3 to Part 2 of Form 1, which explains that the abandonment and reclamation costs deducted in the estimation of future net revenue must include, at minimum, well abandonment costs.
(ii) Assigning Reserves to Undrilled Property
Paragraph 4.2(1)(b) of NI 51-101, which also sets out a general requirement for disclosed reserves data, retains the principle from the 2003 Proposal that total abandonment and reclamation costs (not only well abandonment costs) must be taken into account when determining whether to attribute reserves to an undrilled property.
The provision has been revised to make clear that it applies whenever that determination is being made - that is, at any time the issue arises as to whether reserves should be attributed to an undrilled property to which reserves have not yet been attributed.
We have not altered the principle that this is not necessarily a recurring process once reserves are assigned. (As noted above, paragraph 4.2(1)(c) then applies to require deduction of well abandonment costs in the estimation of the future net revenue attributable to those reserves.)
(iii) Income Taxes Reflected in Reserves Data
We further amended paragraph 4.2(1)(c) (formerly paragraph 4.2(1)(e)) of NI 51-101 to provide, as a general principle, that disclosed future net revenue is to be an after-tax estimate unless the Instrument specifies otherwise (as it does, for example, in certain requirements for disclosure of future net revenue before deduction of future income tax expenses). A parallel amendment to the definition of future net revenue was discussed under “Terminology” above.
(iv) Simpler, More Meaningful Disclosure
A number of commenters on the 2003 Proposal expressed concern about the volume of information and the level of detail required in the annual reserves data disclosure under Part 2 of Form 1. Some argued in effect that the disclosure would exceed investor requirements and in some cases involve disclosure of proprietary information.
The CSA agree that some of that detailed data could be eliminated without depriving investors of the information they need to make informed investment decisions, and that other changes could make the disclosure provided more meaningful.
Revised Part 2 of Form 1 reflects two primary changes:
- Streamlined disclosure -- The 2003 Proposal would have required, under Items 2.1 and 2.2 of Form 1, annual disclosure of components of future net revenue, estimated by year for at least 10 years.
Items 2.1(3)(b) and 2.2(3)(b) of Form 1 now require disclosure only of the aggregate of each component of the future net revenue estimates, using constant and forecast prices and costs respectively. (The revised requirement is illustrated in the revised sample tables on pages 2 and 4 of Appendix 2 to the Companion Policy.) An exception is disclosure of estimated future development costs, for which new Item 5.3(1)(b)(ii) requires disclosure for 5 years.
The result is in some respects also more consistent with the January 2001 recommendations made by the ASC oil and gas taskforce to the CSA.
- Disclosure by production groups -- In a further effort to ensure that more streamlined reserves data disclosure is meaningful for investors, we have built on the concept of “production group” used indirectly in the 2003 Proposal. Future net revenue is now to be disclosed by production group rather than by product type (Items 2.1(3) and 2.2(3)).
Reservoirs typically contain, and wells typically produce, more than one “product type”. For example, an oil well or oil reservoir will often produce, along with crude oil, other products incidental to the production of the oil: solution gas, natural gas liquids and sulphur. Mandatory disclosure separately for each of these product types can require awkward allocations of costs amongst the various product types produced from a single well or reservoir.
Disclosure by product type can also obscure the fact that a reporting issuer can produce natural gas from both natural gas wells and, as solution gas, from oil wells. An investor might consider the distinction important, given that the economics of producing solution gas are likely more affected by physical and economic aspects of oil production than are the economics of producing gas from predominantly gas wells.
(v) Reconciliation Breakdown
The elements to be disclosed in the reserves reconciliation under Item 4.1 of Form 1 have been reordered to correspond to the relevant discussion in the COGE Handbook, and the brief descriptions of those elements have been replaced by new Instruction 3 which directs readers to the COGE Handbook for more extensive guidance.
The 2003 Proposal called for reconciliations for each product type, but an Instruction indicated that it would suffice to provide the information only in respect of the principal product type attributable to a well, reservoir or other reserves entity. To clarify the requirement, Item 4.1(2)(b) now specifies the products for which the reconciliation is required. Revised Instructions confirm that by-products may be disregarded for this purpose.
(c) Other Changes
(i) Responsibility Rests with the Reporting Issuer
Subsections 2.4(1) and 4.2(1) of NI 51-101 now make clear that responsibility for complying with the Instrument rests with the reporting issuer.
(ii) Consent of Reserves Evaluator or Auditor
Subsection 5.7(1) of NI 51-101 has been amended to make clear that not only disclosure of a complete report of a qualified reserves evaluator or auditor, but also disclosure of information derived from that report, requires the written consent of the author, subject to the exceptions set out in subsection 5.7(2).
In response to uncertainty about the effects of this provision evidenced in public comment, we explain the application of this requirement in new Section 5.2 of the Companion Policy.
(iii) Report of Independent Qualified Reserves Evaluator or Auditor
Item 4 of the report set out in Form 51-101F2 (“Form 2”) has been modified to specify that the net present value of future net revenue to be set out in that provision is a pre-tax estimate, to better enable the reader to match it to the reporting issuer’s own disclosure in response to Item 2.2(2) of Form 1.
Section 1.3 of the Companion Policy provides examples to assist reporting issuers in understanding when their disclosure obligations under NI 51-101 first apply to them, depending upon their financial year-ends. The examples set out are unchanged from the 2003 Proposal, but we now emphasize that the examples are based on the assumption of a 140-day deadline for the filing of annual financial statements. We have done so because the CSA are proposing, in a separate initiative, to reduce the annual financial statement filing period from 140 days to 90 days (120 days for “venture issuers”). See proposed National Instrument 51-102 Continuous Disclosure Obligations, published for comment on June 20, 2003 and available on the websites of a number of CSA jurisdictions.
We have also explained that a prospectus filing could accelerate the reporting issuer's first filing obligations under NI 51-101.
(v) Discretionary Exemptions
Part 8 of the Companion Policy discusses the possibility of discretionary exemptions to permit the use of in-house rather than independent reserves evaluations, and the substitution of US-style disclosure for some of the requirements of the Instrument. We have made very limited, non-substantive changes to this discussion:
- Disclosure of exemption to be “reasonably proximate” - The references in sections 8.2, 8.3 and 8.4 to disclosure of a reporting issuer's reliance on a discretionary exemption being “proximate” to the relevant information has been modified to refer to “reasonably proximate”. The purpose is to give reporting issuers some flexibility while ensuring that readers will not be misled.
- In-house evaluations - Section 8.2 of the Companion Policy discusses the possibility of discretionary relief to enable senior producing issuers to rely on in-house reserves evaluations. We have added to the discussion an undertaking of the applicant issuer, which would likely be required for a discretionary exemption, to implement internal procedures that will permit the preparation of the modified reports described in section 8.2.
(vi) Sample Disclosure Tables
The sample disclosure tables in Appendix 2 to the Companion Policy have been amended to reflect the changes in Form 1 described above.