We think this will become useful in the near future. Let us bring you up to speed…

The following is from The Society of Petroleum Engineers (SPE):

• Proved Reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities  will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.
• Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.  It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.
• Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P) Reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate.

Based on additional data and updated interpretations that indicate increased certainty, portions of Possible and Probable Reserves may be re-categorized as Probable and Proved Reserves.

When the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall be provided such that:

• There should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
• There should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
• There should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

Now, if you have some trouble following this, they also have a “non-technical” paper on this:

• The highest valued category of reserves is “proved” reserves. Proved reserves have a “reasonable certainty” of being recovered, which means a high degree of confidence that the volumes will be recovered.  To be clear, reserves must have all commercial aspects addressed.  It is technical issues which separate proved from unproved categories.
• “Probable” or “possible” reserves are lower categories of reserves, commonly combined and referred to as “unproved reserves,” with decreasing levels of technical certainty.
• Probable reserves are volumes that are defined as “less likely to be recovered than proved, but more certain to be recovered than Possible Reserves”.
• Possible reserves are reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves.
• The term 1P is frequently used to denote proved reserves,
• 2P is the sum of proved and probable reserves
• 3P the sum of proved, probable and possible reserves.
• The best estimate of recovery from committed projects is generally considered to be the 2P sum of proved and probable reserves.  Note that these volumes only refer to projects that are currently justified for or already in development.  Total value of any resource base must include an assessment of the contingent and prospective resources as well as reserves.

It is interesting to note that the SEC has a more stringent view (but this is changing, see below):

• The U.S. Securities & Exchange Commission (SEC) System differs from that of SPE in that it only describes Proved Reserves (it does not deal with P2 or P3) and it imposes much stricter evidentiary requirements with respect to the 90 percent confidence limit. The proved developed (PD) categories are virtually identical. The main differences are in three areas with respect to PUD reserves:
• Distance from existing wellbores: SEC requires ‘production continuity’ or the 1-offset rule, i.e. PUD can only be counted if less than 1.5 development radii away from existing wellbores (all of which must have actual economic well tests) or have had a long term production test demonstrating interference. SPE allows indirect evidence (primarily seismic) and interpretation of well log data to be used to interpret the economic limits of a reservoir.
• Proof of oil/water and gas/oil contacts: SEC allows only the lowest known oil/water contact or highest logged oil/gas contact, tested with an actual flow rate to be used in delimiting the oil column thickness. SPE allows extrapolation from formation pressure testing (RFTs) to be used.
• Proof of incremental recovery techniques: SEC generally requires an actual field pilot showing actual incremental oil production for a long-term (six months) duration. The only exception is where there is a very good analog (same horizon, and of as good or better reservoir properties) from another nearby field. SPE generally allows analog application by itself.
• The aggregate result of these differences is that SEC will always be smaller than the SPE reserves. The SEC is preferred by investment banks because it is almost universally used by all public companies and there is less room for interpretation (providing greater consistency to compare different companies).
• SEC classification is very rigid, conservative and based on direct evidence 1-offset rule away from wells; well test with oil flow > econ rate; low-measured OWC.
• SPE classification based on judgement and best “oilfield practice” Demonstration of reservoir continuity; indirect evidence of flow potential (logs); indirect evidence of OWC (pressures).

However, and this is significant, the SEC is coming around to the views of the SPE..

• The Securities and Exchange Commission has finally proposed a revamp of the way it allows E&P companies to report their proved, probable and possible reserves estimates. This is long over-due–about 25 years and “an extended-reach well that’s been frac’ed” overdue.
• Industry has long argued that due to technology advances since the 1970s, when the SEC last updated its reserve-reporting standards, the definitions of proved (P1), probable (P2) and possible (P3) reserves are much easier to derive, and more accurate. Production from P2 reserves has become more likely as well.
• Asset buyers have recognized this in spades, paying more for proved undeveloped reserves than ever before, and assigning more dollar value to the P2 and maybe even P3 categories as well.
• “To maximize value, package up all your production, PUDs and probables,” advised Kayne Anderson’s Chuck Yates at the Cosco Private Capital for Energy Forum in 2005. “You’ll get more than by just selling your production. These serial buyers will pay for your probables.”
• Now the stock market will too. Imagine the changes upward in all numbers as E&Ps in unconventional plays bring their vast P2 and P3 estimates onto their reserves reports and 10Ks! Now that which CEOs spoke of in their presentations can move from being grand statements of optimism to real numbers on a page.
• This changes the landscape. Those multi-trillions of cubic feet of gas that Petrohawk CEO Floyd Wilson speaks of in the Haynesville, and Ultra Petroleum CEO Mike Watford speaks of in Jonah Field, Wyoming, seem more than a distant promise now.
• In-house reservoir engineers and third-party groups like Netherland Sewell or Ryder Scott will have their hands full, drilling deeper into the data and estimates on P2 and P3 reserves.
• Investors and analysts will be like kids in the candy store, once they start pouring over this new data. Disappointments and surprises will no doubt surface, but for most E&P companies, this SEC change is good news that will lead to increased valuations. [Leslie Haines, Oil and Gas Investor, Editor in chief]

By the way, if you wondered why it takes so long for Netherland Sewell to come up to the report with the estimates for IOC, now you have at least one reason..

Something else is useful. The message board trolls continuously argue that IOC has no reserves according to SEC filings. Indeed. But it’s only a matter of time..