When Royal Dutch/Shell
(Shell) announced it was reclassifying 20 percent of its recoverable reserves
of hydrocarbons in January, shock waves rippled not only through the oil and
gas industry but also the financial and regulatory arenas (see Geotimes,
March 2004). Since then, the company has downgraded an additional 3 percent
of its reserves, seen the departure of several top executives, and faced both
investors’ ire and investigations from the U.S. Securities and Exchange
Commission (SEC) and the British Financial Services Authority; the investigations
ended in payments of $151 million in fines. In the wake of the Shell debacle,
several other oil companies have also downgraded their reserves, leaving investors
and policy-makers wondering what should be done about it.
“In the past, when we’ve seen a rash of write-downs, it’s been
related to an oil price collapse,” says Matthew Simmons, Chief Executive
Officer of Simmons & Company International. “The irony is that now
we’re seeing reserves write-downs with globally high prices.” That’s
because companies have been “overly optimistic” for several years,
he says.
El Paso Corporation in Houston, Texas, which recategorized 35 percent of its
reserves in February and is under investigation by SEC, said that the reclassification
was due to “certain employees [who] used aggressive and, at times, unsupportable
methods to book proved reserves.” Shell has said that its proved reserves
“did not in all cases properly reflect the maturity of the development
projects concerned.” Other companies, such as Denver-based Forest Oil,
which downgraded its reserves by 25 percent this year, claim production on certain
fields was lower than expected.
Rebooking reserves from one category to another stems from “confusion about
what exactly reserves are” and how they are classified, says Thomas Ahlbrandt,
chief of the World Energy Project at the U.S. Geological Survey. The term “reserves”
refers to the amount of oil or gas that has been discovered in an individual
field and that can be extracted with existing technology under present economic
conditions. Classifying reserves, however, is a bit more problematic. Worldwide,
more than 150 different classifications are in use, according to experts working
with the United Nations.
While the exact definitions and terms vary, there are three common ones —
proved reserves (the target of most of the rebookings), probable reserves and
possible reserves — with fairly uniform standards, Simmons says. The classification
system is so complicated, he says, that “you can have 20 experts looking
at the same data and coming up with completely different estimates” of
categorized reserves. An additional part of the problem, Simmons says, is that
in the last few decades, companies have cut back on the processes involved in
exploration, largely due to low oil market prices leaving less money for further
development. While hydrocarbon exploration technologies have improved, for example
with 3-D seismic imaging, many companies have replaced drilling traditional
test wells with the new data, much to the detriment of the industry, he says.
To accurately assess a hydrocarbon reservoir, Simmons says, nothing can replace
drill holes.
In order to eliminate some of the uncertainty and confusion, and at least get
everyone on the same page about what constitutes a reserve’s classification,
geologists, oil industry executives, auditors and policy-makers are coming together
to discuss changes.
Reserves 2004, for example, is a series of seven workshops, convened by the
Energy Forum and limited to oil and gas industry people. “The key is that
everyone is given equal footing here, whether they’re from one of the big
oil companies or a mom-and-pop company,” says David Hughes of the Energy
Forum. A record of the workshop discussion is sent to SEC, but the statements
are anonymously attributed, Hughes says.
Roger Schwall of SEC attended the first workshop in April, which focused on
estimating and reporting and avoiding write-downs. He said at the roundtable
that SEC is not “getting ready to change any of our rules but when we hear
what people are saying, we certainly are analyzing it and considering it.”
Still, SEC spokesman John Heine says that the official position is that “there
is nothing pending before the commission.”
Congress has also been following the rash of reserves write-downs and convened
a hearing in late July before the House Committee on Financial Services to discuss
the “growing unease in the industry about a widespread tendency to overbook
reserves,” as Rep. Michael Oxley (R-Ohio) said in a statement. Simmons
and other industry insiders testified before the committee that the system is
in need of reform.
Rep. John Dingell (D-Mich.) agreed, urging the Financial Services Accounting
Board to “undertake a standard-setting project in consultation with the
appropriate accounting and energy regulators with all deliberate speed.”
In the coming months, the committee will continue to assess what additional
steps need to be taken to ensure that the oil companies’ reserves estimates
are legitimate, although another hearing is not scheduled.
Meanwhile, the United Nations continues work on devising a new reporting system.
In January, an ad hoc group of experts finished the U.N. Framework Classification
(UNFC) for Energy and Mineral Resources.
After a public comment period and editing, the U.N. Economic and Social Council
accepted and recommended the UNFC for worldwide application in July, says Sigurd
Heiberg, a geologist at Statoil in Norway and chairman of the ad hoc committee.
The International Accounting Standards Board will consider the UNFC later this
year, as the board develops new financial accounting standards for extractive
industries, Heiberg says. “The UNFC provides a much broader framework that
will accommodate the known systems and provide a level of commonality that should
eliminate some of the reclassifications,” says Elliott Young, a geologist
with ExxonMobil who also served on the committee.
Limiting the potential for another rash of reclassifications such as those that
have occurred over the past few months is just what needs to happen, Simmons
says. Unfortunately, “over the next two to three years, I think we’re
going to see a lot more write-downs,” he says. “The chickens will
come home to roost.”
Megan Sever
| One
field, six companies, six numbers Ormen Lange, a large gas field 100 kilometers off the coast of Norway in the North Sea discovered in 1997, is in many ways a microcosm for the challenges the oil and gas industry faces when booking reserves. Five oil and gas companies and a Norwegian state-owned company share a stake in the development of the field — and each company has booked different numbers for the proved reserves in the field. The Ormen Lange field illustrates that the problem in reserves bookings is systemic, says Matthew Simmons of Simmons & Company International. The issue, he says, is in the definition of proved reserves — generally described as the amount of oil and gas believed to be recoverable with reasonable certainty under current economic conditions (see main story). Each company bases its reserves bookings on a series of estimates and comes up with a different number, which leads to confusion about the total recoverable energy available globally, Simmons says. Furthermore, he wonders how much the owners of this “extremely challenging field” actually know about the total recoverable reserves. Companies rushed to book proved reserves, Simmons says, so the “capital cost of these huge projects gets capitalized and written off over the life of the proved reserves.” After Shell’s initial reserves reclassification in January, the company downgraded its proved reserves at Ormen Lange from roughly 60 to 20 percent in March. Months later, in June, Norsk Hydro of Norway, which originally booked close to 80 percent proved reserves in filings with the U.S. Securities and Exchange Commission (SEC), announced a 30-percent reduction in its proved reserves. BP has stuck to its original booking of around 80 percent proved reserves for Ormen Lange. Norwegian firm Statoil and ExxonMobil, two other stakeholders in the field, booked their proved reserves closer to 30 percent. State-owned Petoro of Norway, which owns the majority of the field, is not required to file proved reserves with SEC. One number the companies seem to agree on, however, is the amount of gas available in the field: about 400 billion cubic meters. But, Simmons adds, only a few test wells have been drilled in the field so far, with the rest of the data from seismic testing. Official figures from Norsk Hydro place the 40-kilometer-long and 8-kilometer-wide reservoir about 3,000 meters below the surface of the sea and suggest that the field will produce 20 billion cubic meters of gas per year. Once Ormen Lange is developed, extracted gas will travel via a 1,200-kilometer-long pipeline from its processing site at Nyhamna, Norway, to England. Development costs are expected to be around $9.54 billion, and production is scheduled to begin in 2006, with gas reaching the market in 2007. MS |
Link:
"(Re)Classifying
oil reserves," Geotimes, March 2004
 |
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