The Alberta Securities Commission and a new APEGGA Practice
Standard have made reporting oil-and-gas reserves a more
standard and verifiable process.
BY NEIL MARSHALL, P.ENG.
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
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
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
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