Marcellus Shale

Rogers Natural Gas Spin Cycle

Dr. Scott Cline
PhD, Petroleum Engineering

Part III in a series entitled “Mother of All Spin” about Deborah Rogers’ New York speaking tour.

Parts I and II of our series reported on the macro and micro-economics and lack thereof in Deborah Rogers’ presentations.  She goes still further into the weeds, however, when she tries to make some technical arguments to boost her claim that some companies are artificially inflating reserve estimates by introducing the “b” factor without explaining what it means and how it is used. She simply tells the audience, to further reinforce her bogus overstated reserve theory, that it is her “understanding” the “b” factors used by many operators are too high thus resulting in overstated reserves. She claims the Society of Petroleum Evaluation Engineers “cautions against using a value over 1 as it may not represent reality.”

Is that vague enough for you? Again, this misrepresentation shows her method of taking something somebody told her, that she either never understood, or never wanted to understand, and spinning a tale to fit her needs.

A “B” Grade Presentation at Best

The “b” factor that Ms Rogers unsuccessfully described is simply a coefficient and exponent used in the Arps decline curve equation to model either exponential, hyperbolic or exponential production decline, depending on the reservoir and production characteristics. Exponential decline, using the b value of zero is exhibited by a straight line on a semi-log graph, whereas hyperbolic decline with b values ranging from zero to 1 represent a decline that is characterized by an early steep drop followed by flattening, which is typical of tight gas formations including shale.

In modeling shale gas decline, it is not uncommon for reservoir engineers to use values well in excess of 1, which while outside the parameters prescribed by Arps back in 1945, nevertheless fit the early production profile. The problem with values greater than one over the entire life of the well is that they will approach unreasonable amounts. But, what Rogers failed to say is that, in real life, petroleum reservoir engineer’s deal with this situation by applying professional judgment in using a b factor in excess of 1 to model the early production, and then forcing the late part of the well life to exponential decline.

So, using a “b” value in excess of 1 for the early flow regime is widely accepted and used, but it is not blindly used in isolation.

Other methods used by engineers in tight and shale gas reservoirs include the power law decline analysis method, if bottom-hole flowing pressure over time is known, Continuous EUR methods of Currie, Ilk and Blasingame (SPE 132352), Dr. John Lee’s stretched exponential decline (SPE paper 130102) and others.

Comparison of Decline Curves

But, in actuality, curve fitting is only one of a large arsenal of reservoir evaluation techniques used to evaluate reserves and resources. Some others include reservoir simulation, pressure transient analysis, fracture architecture modeling and various other decline curve analysis techniques. Petroleum engineers are well educated, seasoned professionals who use their best judgment in projecting reserves. Different engineers may come up with different estimates, but I have not seen any evidence to support intentionally inflated reserves.

To simply slap a slide up on the screen, as Rogers did  and say “b” values in excess of 1 indicate industry abuse is absurd.

Reserve Reporting for Me, But Not For Thee

Rogers then makes quite a point to talk about a SEC reserve reporting rule change (that went into effect for reporting after January 1, 2010 and early compliance was forbidden). Her theme was that this was the golden opportunity for companies to inappropriately raise reserves, thus allowing increased loan and investment access and further defrauding investors. And she goes on to say that, since third party engineering reserve certifications were not required for public companies, the company estimates could not be trusted.

A little background is necessary to expose the spin here. When teaching corporate finance classes, one of the first things I explain to classes is that accounting rules and regulations in general are evolutionary. They are occasionally adjusted to adapt to new industries, technologies, changes within industries, new concepts and are done so only after very careful consideration, comment periods and analysis. The purpose is give the most accurate, consistent and comparable portrayal of a company’s financial condition.

So it was with the first update in reserve reporting since 1983. The new rules put in place attempt to provide investors with a more complete picture of public company reserves by recognizing the technologies and reserve quantification methods that have emerged and developed over the last several decades. I believe I heard Ms Rogers even say she agreed there were some good reasons for the update.

The U.S. Securities and Exchange Commission (SEC) adopted revisions to its rules governing oil and natural gas reserves reporting that are essentially aligned with and incorporate many of the definitions in the Society of Petroleum Engineers (SPE) Petroleum Resources Management System (PRMS). Those companies with SEC reporting obligations are mandated to use the new rules for all reporting after January 1, 2010 including the filing of annual reports for fiscal year end 2009, which were typically filed in January, 2010.

In the past, for proved reserve estimates (those with great certainty), which were the only estimates allowed to be reported, companies were only able to use actual production decline analysis and flow test data to meet the reasonable certainty tests. With the new changes, companies may now use other newer methods, but they must provide a succinct description of technologies used when the reserves are first booked. And, rather than basing the economically producible price on the last day of the year, as the prior rules mandated, the new rules provide that the price used for existing economic conditions must be a twelve-month average, using an un-weighted average of the price on the first day of each month. Alternatively, reported prices can be based on existing contractual arrangements.

A 5-year development rule was also instituted for booking proved undeveloped reserves. In addition companies may, but are not obligated to disclose estimates of unproved or risked resource potential. More on this topic later.

In regard to third party reserve certifications and reports, they are not required, but both are frequently done for smaller companies with less staff and expertise.  If they are used, the new rules provide that the company must include a report that summarizes the tasks performed and the conclusions reached by the third party, a checklist of specific items to be included in the report, such as the proportion of the company’s reserves covered by the report and their location, along with the methodology and assumptions that went into making the reserve calculations. Whether or not a third party prepares or certifies the company’s reserve estimates, the new rules require disclosure of the reserve engineer’s qualifications, a general discussion describing the safeguards maintained to protect the objectivity and integrity of the company’s reporting process must be included in the reserve report whether or not a third party is used .

So now with a little background, let’s look at the areas Rogers indicates lead to abuse.

She makes a big point of saying companies are violating the 5-year rule. She claims that according to a Ryder Scott, well known petroleum engineering valuation firm, some 80% of companies are not in compliance with the 5-year rule. She says this in an apparent effort to portray an outlandish disregard of the rules by oil and gas companies in an attempt to inflate reserves.

The point of the rule isn’t to say that the only reserves that are bookable as proved are those that can be reasonably produced within the next five years.  Scott Rees, chairman and chief executive officer of reservoir-evaluation firm Netherland, Sewell & Associates Inc., describes the SEC’s new view of a five-year rule on booking proved reserves this way:

The SEC says five years is a reasonable plan of development. Anything past five years, there should be some circumstance that makes sense for (booking) that.

So for example, an operator may have a several-year history of developing 20 wells per year in a play with predictable results, and all indications are this program will continue beyond five years. The operator may have a good claim to book more of the reserves as proved than only what may be developed in the next five years. The rule change did allow for companies to expand their scope of proved undeveloped reserves (PUDs) beyond those immediately adjacent based on new technologies as long as they meet the five year development plan.

However, a company that books or intends to book PUDs that will remain undeveloped for more than five years has a significant burden of proof. They must be prepared to explain that determination to the SEC, including:

• how the determination complies with the compliance and disclosure interpretations on the new PUDs definition;

• the factors that limit the pace of project development;

• any environmental restrictions on development; and

• other factors that will likely cause development to take longer than five years.

SEC Logo

The SEC may also request a detailed description of the nature, current status and planned future activities of the projects underlying the PUDs. A company with low historical PUD conversion rates will need to explain how it intends to develop its PUDs within five years of booking them as proved and what the conversion rates were for the prior three years.

Admittedly, because this is a bit of a gray area, subject to scrutiny by the SEC, there are and will continue to be conversations between the SEC and companies each year and there may be disagreements that must be reconciled. But this is expected and indicates openness and cooperation; not the concealment and willful disregard Rogers portrays.  She is all to ready to interpret and report but denies the same to the experts who really know.

Furthermore, quantifying reserve increase impact from simply the rule change alone would be impossible, as many other factors are involved, most notably related to continuing operations and improving extraction technology. Many observers actually think the 5-year rule may in some cases contribute to reduction of PUDs that were already on the books, that have passed the 5-year development test and may need to be removed.

A Stock of Unfounded Assertions

Finally, Rogers says ExxonMobil only got into the shale play by buying XTO because of the new SEC rule change, which allowed companies to simply increase reserves through a rule change.

The SEC rule change did not come into effect until after January 1, 2010 (with early adoption notably prohibited!) and any public reserve reporting affected by that change would not have come until the end of 2009 and typically reported in January, 2010. The ExxonMobil purchase of XTO happened in 2009. And, besides, it is naïve to think ExxonMobil would buy a company based simply on XTO’s SEC reported reserves anyway. They would do their own due diligence, come up with their own estimates, value them and make a purchase based on the economics and their long-term outlook.

The late entry of ExxonMobil and other majors had more to do with the fact large companies do not move very quickly, but once they recognized the enormous resource potential they have dramatically entered the arena with substantial investments.

There is still more to say on this subject, so please check in tomorrow for Part IV, our final post in the “Mother of All Spin” series …

If you missed Part I, entitled “Natural Gas Critic Refuses to See What’s Before Her Eyes,” check it out here.

If you missed Part II, entitled “Where Is That Natural Gas Treadmill?” you can find it here.

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Dr. Cline holds s a BS in geological science from Penn State, and both MS and PhD in petroleum engineering from University of Oklahoma and an MBA. He began his career in 1976 for Gulf Oil Corporation (now Chevron) and later worked as geophysicist, geologist, petroleum engineer, and senior manager for several other oil and gas companies based in Houston and Oklahoma City. He currently lives in the Finger Lakes region of NY and consults to the oil and gas industry. He also teaches corporate finance and is an accredited business valuation specialist. He was involved in the early study and implementation of horizontal drilling , published on a wide range of oil and gas topics and his research interests include horizontal drilling in fractured reservoirs, well construction and design, reservoir simulation, fluid flow in porous media, oil and gas valuation, reserve and resource estimation, and unitization matters. His PhD dissertation was on decline curve analysis of horizontal and vertical wells in fractured reservoirs. He has recently served as subject matter expert at the US EPA technical sessions on well construction and hydraulic fracturing in Arlington, VA, the Quebec’s Office of Public Hearings on the Environment (BAPE) in regard to formulating oil and gas regulation in Quebec and testified before the NY State Assembly Energy and Environmental Committees on hydraulic fracturing.
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