SEC Rules Changes for Oil & Gas Reserves

Yesterday I was talking about the calculation of reserves for coal mines, and the calculation of what a reserve holds is a critical part of raising the capital to put a mine in place. The same holds true about oil and gas wells, as their price rises above $5 million a well, and at the end of last year the SEC changed the rules on Oil and Gas Reserve Reporting. It is interesting to read the rationale for the changes. Part of the problem has been that the industry has been developing technologies that make it easier to economically extract oil from tar sands, and also to get natural gas from coal seams and from shales that had previously been uneconomical to develop. However, where the rules that define reserves do not allow a full accounting of the volumes that can be recovered, then it becomes harder to raise capital for the operation. The rules were last written in the time that most extraction came from the historic vertical wells that drilled down into a deposit and extracted the gas. With both coal and shale extraction the new technologies have advanced considerably beyond this, and to make the situation more realistic the rules had to be changed.

In the extraction of gas from shale beds, for example, the rock is normally made up of very fine grains, which provide very poor permeability (or passageways) for the gas to work through the rock to get to any well that is there. Rates of flow to the well would thus be too slow to be economic. To enhance the flow operators therefore drill long horizontal holes along the layer of rock holding the gas. Pressure in the well is then raised, until cracks are created in the wall of the well, and with more pressure these are extended out into the rock providing a path for the gas to flow back to the well. While this technique (of which more some future Sunday) creates passages through the rock that allow the gas to flow to the well in larger volumes, and makes the well potentially economically viable it has put artificial connections into the rock. Part of the old definition of reserves was that the oil/gas already had the connections in place in the rock to ensure that the fluid could flow to the well if it was drilled. Further the presence of oil had to be proved by drilling a well into the rock and actually showing that it was there. Thus the term “proved oil and gas reserves.”

To recognize that there are more sophisticated tools that can now tell much more about the presence of oil/gas in a rock without needing to drill that proving well, the SEC have changed the rules to read:

The proposed revisions to the definition of “proved oil and gas reserves” also included provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations. We are adopting those revisions as proposed.

We also are adopting, as proposed, revisions that permit a company to claim proved reserves beyond those development spacing areas that are immediately adjacent to developed spacing areas if the company can establish with reasonable certainty that these reserves are economically producible. These revisions are designed to permit the use of alternative technologies to establish proved reserves in lieu of requiring companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells.

Of course having written such a statement, one has to clarify what is meant by “high degree of certainty” (since there is no longer the physical evidence of oil on the end of the “dipstick”). This they have done by definition:

Therefore, we are adopting the “high degree of confidence” standard that exists in the PRMS. We also are clarifying that having a “high degree of confidence” means that a quantity is “much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease” to provide elaboration to the definition of reasonable certainty.

The other change that I want to highlight comes in the estimation, knowing that an existing site has oil/gas, as to how far out from that point the field can be considered to extend, and this is known as the “undeveloped reserve.” Here the decision is based on the degree of certainty that the field actually extends into that space. And the language has been loosened to make it easier to include those more distant reserves.

In the Proposing Release, we proposed a significantly revised definition of the term “proved undeveloped oil and gas reserves.”

The most significant aspect of the proposed revision was the replacement of the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test. Currently, the definition of the term “proved undeveloped reserves” imposes a “reasonable certainty” standard for reserves in drilling units immediately adjacent to the drilling unit containing a producing well and a “certainty” standard for reserves in drilling units beyond the immediately adjacent drilling units.104 All commenters on this issue supported the proposal. Three commenters noted that a single standard—reasonable certainty—should apply to all proved reserves. We are adopting this aspect of the definition as proposed.

Since the companies no longer have to actually drill into a formation and prove the oil is there the old fashioned way, the big question transfers to the reliability of the technologies that are used to determine that oil is actually present. And here, since technologies continue to change, the words have been generalized

We also proposed to define the term “reliable technology,” expressed in probabilistic terms, as technology that has been proven empirically to lead to correct conclusions in 90% or more of its applications. Several commenters expressed concern that this proposed 90% threshold would be difficult to verify and support on an ongoing basis. We agree that a bright line test would be difficult to apply to a particular technology or mix of technologies to determine their reliability. Therefore, we are not adopting the 90% threshold as part of the definition.

And while changing the rules to include production from tar sands can be readily easily accomplished:

Our current definition of “oil and gas producing activities” explicitly excludes sources of oil and gas from “non-traditional” or “unconventional” sources, that is, sources that involve extraction by means other than “traditional” oil and gas wells. These other sources include bitumen extracted from oil sands, as well as oil and gas extracted from coal and shales, even though some of these resources are sometimes extracted through wells, as opposed to mining and surface processing. However, such sources are increasingly providing energy resources to the world due in part to advancements in extraction and processing technology. Therefore, the rules we adopt today revise the definition of “oil and gas producing activities” to include such activities.

However it does require a definition of bitumen, which they provide

We are defining the term “bitumen” as “petroleum in a solid or semi-solid state in natural deposits. In its natural state, it usually contains sulfur, metals, and other non- hydrocarbons. Bitumen has a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.”

And to address the point that I began with about accumulations of gas in unconventional places the regulations will change:

Although we agree conceptually that the focus of reserves disclosure should be on the final product, we also recognize that the production of oil and gas from varying sources can have significantly different economics. Extraction of oil and gas from continuous accumulations can be much more labor and resource intensive than extraction of oil and gas from traditional wells. They often require greater ongoing efforts and expense after the initial extraction equipment is in place, making such operations more sensitive to price fluctuations.

We agree with the commenters that disclosure based on the end product sold would provide a more effective basis for distinguishing reserves that disclosure based on the type of accumulation in which the reserves are held. Therefore, we have revised the disclosure to be based on the end product that is sold by the company However, with respect to the end product, new Item 1202 makes a distinction between oil and gas, on the one hand, and synthetic oil and gas, on the other. Synthetic products require processing of the raw resource material, either while it is still in the ground (“in situ”) or after it is extracted, before it can be used as refinery feedstock or as natural gas. Such processes currently include bitumen upgrading as well as coal liquefaction and gasification. However, resources from some continuous accumulations, such as coalbed methane, do not require such processing and therefore are not associated with the same level of ongoing costs once a well has been drilled because the in-ground resource is already oil or gas (in the case of coalbed methane, the in-ground resource is methane, trapped in a coalbed). Thus, coalbed methane would not be considered a synthetic product.

I think it is a fair comment to note that these relaxations of the rules will allow companies to claim significantly larger reserves, than heretofore allowed, although it should be born in mind that it actually won’t change the actual volumes of oil and gas in the ground by one molecule.