New – And New Again – Strategies Help
Maximize Reserves Under NI 51-101

The Alberta Securities Commission and a new APEGGA Practice Standard have made reporting oil-and-gas reserves a more standard and verifiable process.


Annual reports in 2004 saw the results of the introduction of National Instrument 51-101. Industry giants and junior oil and gas companies alike were forced to write-down their reserve numbers under the stricter NI 51-101 criteria.

The intention of NI 51-101 was not to dramatically change the way reserves are calculated, but rather to standardize and make the evaluation criteria explicit. Investors and industry practitioners felt the ripple effect of the highly publicized corporate scandals of the late 1990s that prompted the creation of NI 51-101. Incidents of overstating shook investor trust and confidence, and called into question the validity of engineering reports.

The desire to report low finding costs per BOE caused some oil and gas companies to selectively report their finding and development costs, and to maximize reported proven reserves. The drive to show sustainable growth to investors pushed reserve evaluations to their limits.

Part of the problem was that the rules weren’t all that clear to begin with. Strictly speaking, many of the evaluation scandals were merely optimistic interpretations. Moreover, the previous guidelines lacked management accountability, leaving the evaluation industry open to public mistrust and accusations of intentional deception.



Canadian Council of Professional Geoscientists

Alberta Securities Commission

APEGGA Practice Standard

NI 51-101 was developed by the ASC on behalf of the 13
provincial and territorial securities commissions, which together form
the Canadian Securities Administrators (CSA). Other CSA members
will consider adopting the rule over the next few months.

Evaluation engineers were caught in the fray – forced to choose between upholding vague industry guidelines and succumbing to pressure from their employers to push the limits of interpretation. APEGGA was brought into the process, at the urging of the Alberta Securities Commission.

The result: National Instrument 51-101 and a new APEGGA practice standard. NI 51-101 was developed by the Alberta Securities Commission on behalf of the 13 provincial and territorial securities commissions, which together form the Canadian Securities Administrators.

The instrument and the associated Canadian Oil and Gas Evaluation Handbook restrict potential abuses of interpretation by clearly defining evaluation practices. Both are referred to in APEGGA’s Practice Standard for the Evaluation of Oil and Gas Reserves for Public Disclosure.

NI 51-101 outlines the new definitions and reporting requirements that came into effect in September 2003. These requirements include evaluation by a qualified reserves evaluator, and standardized calculation methods for finding and development costs, and for benchmark pricing. The reserves definitions have changed from “a degree of certainty” to an assigned probability that the quantities actually recovered will equal or exceed the estimated reserves.

Considered the conservative estimate, proven reserves are assigned a 90 per cent probability that the actual quantities recovered will equal or exceed the estimate. Probable reserves are assigned a probability of 50 per cent, and possible reserves are classified as the long shot with only a 10 per cent probability.

Oil and gas companies were previously able to book proven reserves based on similar log data. NI 51-101 states “confirmation of commercial productivity of an accumulation by a production or formation test is required for classification of reserves as proved.”

While the stricter NI 51-101 regulations are forcing oil and gas companies to re-evaluate their reserves and rein in optimistic evaluation practices, it’s also making an old technology new again. Drillstem testing, which my company and others offer, is re-emerging as a method for maximizing proven reserves under the new requirement that hydrocarbons be flow tested at commercial rates before reserves can be classified as proven.

Drillstem tests have long been used to evaluate wells where log data is inconclusive. However, the use of these short flow tests declined when the introduction of neutron-density logs in the 1970s combined with low gas prices to make the identification of commercial zones obvious.

In recent years, high gas prices are making it more difficult to identify commercial zones from log data alone. With the addition of the NI 51-101 requirement that proven reserves be flow tested, drillstem testing is once again a sound strategy for maximizing reserves.

Drillstem tests are conducted in the open hole before casing is cemented and cost far less than testing after casing, especially when multiple zones are being evaluated. When responding to the needs of employers to maximize reserves, reservoir engineers now run DSTs to get credit for reserves in thin zones that would otherwise not make it to the reserve report.

Before NI 51-101, analogous data from an offset well might have been sufficient, but now, as one of my customers reported: “Without a DST I have no hope. With one, I have an argument.”

NI 51-101 attempts to improve an investor’s ability to compare oil and gas stocks by defining reserves categories, evaluation practices and attaching a high degree of accountability at the board of director level for reserves reporting. Management must present a realistic picture of reserves and finding costs.

The handbook imposes testing requirements, benchmark pricing and standardized methods for calculating finding costs. Evaluation engineers who adhere to the practices outlined in NI 51-101 and the handbook will protect themselves and management from accusations of deceit – and give investors a level playing field by which to compare companies.

Neil Marshall, P.Eng., is president of Calgary-based Northstar Drillstem Testers Inc., specializing in drillstem testing worldwide. He has more than 35 years of experience in the oil industry.

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