On January 9, 2004, the Royal Dutch Shell Group announced that internal reviews revealed that certain proved oil reserves would be re—categorized. The ensuing months have seen headlines blare story after story portraying a scandal—ridden company, as the company's stockholders have seen the value of their investment shrink. A number of top managers, including the chief financial officer have stepped down, and criminal investigations are underway.

The general public depends on a steady supply of energy, even more than it depends on the integrity of corporate financial reporting. But public understanding of the very concept of oil reserves is incomplete at best. Accordingly, The American Thinker is presenting a primer for readers on the subject of oil reserves, and their reporting regulations.

Shell moved a total of 3.9 billion barrels of oil equivalent would from 'proved reserves' to other categories. The term 'barrels of oil equivalent' ('boe') is commonly used to include other hydrocarbons like condensate and natural gas liquids (NGL) in the calculation of energy resources. The write—down of 3.9 Billion bbls represented a virtual disaster to investors, and the stock quickly dropped 10% on heavy volume.

The largest of the changes moved 2.3 billion barrels of 'proved reserves' in mature oil fields in Nigeria and Oman from the category 'proved undeveloped' to 'non economic.' In the case of Nigeria, the affected reserves were in a mature area covering some 31,000 square kilometers, including 324 fields, 3198 oil reservoirs, and a substantial infrastructure necessary to produce from these fields. According to Shell's published information, this area contained more than 1000 producing wells, 87 flow stations and 8900 kilometers of flow lines and pipelines. You can conclude from this level of development that Shell understood these fields very well, and that a preponderance of data indicated the original estimate for proved reserves was too high.

The changes announced by Shell were later portrayed as the result of management incompetence. Plaintiffs in following lawsuits claim that the large overstatements cannot be just due to error, or accident, but were deliberately overstated to bolster their credit ratings. Because oil reserves are part of official filings with the US Securities and Exchange Commission and various foreign financial agencies, criminal prosecutions are possible.

Aside from the shock and awe of a 20% write—down, the reserves adjustments submitted were actually not terribly unusual for any oil and gas company. Although based on intensive use of scientific data, there is always an element of uncertainty in the calculation and categorization of oil reserves. Note that new development may reveal oil that is not economic because of the production method required to actually produce the oil, and a write—down may be required to meet the definition of 'proved reserves.'

Royal Dutch Shell uses a common technique for classifying oil reserves. The basic three reserves categories are (1) 'possible' (2) 'probable' and (3) 'proved reserves.' The 'proved reserves' category is further broken down into 'developed' and 'undeveloped' reserves. Shell reported that 90% of its total change was a reduction of the 'proved undeveloped' category, with the balance from the 'proved developed' category.

Why did Shell do it? Shell claims that a planned re—organization prompted a review of proven reserves to ensure a global standard across the organization.

Regulatory developments
The SEC has been under fire for some time about the standard it uses for reporting oil reserves, a system developed almost 25 years ago. Many oil companies have recently received letters of inquiry about their reserves, prompting speculation that the SEC is looking for more companies, which have claimed proven reserves without following their rules. These inquiries have introduced concern among the investment community and the operating oil companies. Many critics of the established standard point out that technology has changed considerably in the last 25 years, and an update is overdue.

Our neighbors in Canada have recently approved a new standard for reporting reserves. Canada historically had the weakest standard, requiring only a reasonable certainty of realized reserves. There were no economic requirements or testing requirements. This was dangerous business, especially with the smaller companies, which could experience drastic swings in stock price for each discovery. The new Canadian standards were developed after a nasty set of reserves scandals in the 1990's.

Canadian Bill 51—101 calls for publicly—traded oil and gas companies to hire independent auditors to place numbers on reserves. Interestingly, Canada's eight largest producers, and any others that produce more than 100,000 barrels of oil equivalent, are exempt from the standards. The implication is that Canadian authorities are really targeting smaller companies, where exploration activity inherently generates more volatility in stock price and potential investor concerns.

Many Canadian energy companies, such as Petro—Canada, Nexen, and Husky Energy, have seen their stocks take a beating after writing off significant reserves. Although painful for existing stockholders, this is ultimately good news for investors, because they now have a level playing field.

As the American SEC considers new standards, it should examine Canada's experience. The Canadian Securities Agency (CSA) drafted these standards with the assistance of the oil and gas industry. The current process in our own SEC is more of a mystery to industry members, because no one is talking. Many companies on both sides of the border are lobbying for comparable US and Canadian standards, simply to avoid confusion.

Investor confidence is just returning to the US markets after a variety of scandals. The last thing we need in the US stock market is a new round of scandals to undermine this confidence. The left already attacks Big Oil at every opportunity. A new round of oil reserve reclassification shrouded in mystery, or implemented with undue opaqueness will not help the public understand the energy problems we have. Frankly, I want to see the SEC provide some leadership and update the US standards. This is SEC's problem to fix, and they need to be on the case.

 
So, what is an investor to think?

There are real problems with the SEC standard established in 1980, which defines proved reserves. The SEC would have us believe that the process of calculating reserves is a simple matter of 'science,' not a probabilistic exercise. In other words, the SEC thinks this it is an arithmetic or accounting issue to calculate reserves, and therefore there should be no mistakes. This is patent nonsense.

The current SEC presumption of inerrancy is not a realistic standard for investors, as can be demonstrated by the process currently used to calculate oil reserves. At all phases of a new project, a company gathers and analyzes information from a variety of sources, including subsurface methods such as drilling, logging and drill stem tests; surface methods such as surface geology, conventional seismic imaging, and 3—D seismic imaging; and, aerial methods such as aerial photography, magnetic surveys and gravity surveys.

In each and every case, the process includes making judgments from interpreted data.

Let's assume that a possible subsurface hydrocarbons play is identified by a variety of geophysical methods and we drill an exploration well. By this stage, the exploration geologist has estimated the area of the field (e.g., square miles), approximate subsurface depth in feet, and estimated thickness (feet) of the objective rock formation , called net pay. During the drilling process, the wellsite geologist may actually identify traces of oil in the rocks that are returned to the surface by the drilling fluid (mud).

Once the drillers reach the objective rock formation, a series of technical data is gathered in a process called logging, and actual core samples of the objective formation are gathered using a special coring tool. Finally, a drill stem test can be run to determine if the target rock formation will flow oil.

From this technical data and rock samples taken in a hole about six inches in diameter and several thousand feet deep, the exploration team can determine the geology of the potential oil reservoir, and engineering data of the fluids in the formations. For example, we can estimate porosity, which is the percentage of the rock that is pore space that can hold fluids. We can estimate permeability, which is the ability of rock fluids to actually flow. From the fluids one can calculate pressure, temperature, saturation, density and viscosity.

Certainly science is used to calculate these factors. However this data is gathered from a single data point in the subsurface. As we gather more information from more drilling, or other scientific data sources, the geologist can estimate what actual volume of oil the entire area is capable of producing. This volume of oil is called the reserves number.

It is less than credible to believe that data extrapolation to the entire reservoir area is anything but probabilistic. From a range of data, the geologist can estimate the probability of economic reserves in the categories of possible (eg, 10%), probable (eg, 50%) or proved (eg, 90%). It should be highlighted that there is no scientific certainty in this process, only the application of science and judgment to minimize risk.

By the very nature of the exploration and development process, possible or probable reserves are converted to proved reserves after more drilling, or more detailed seismic studies. This increases the odds of success and, therefore, attracts more investment dollars to complete the development process. It is very clear that further drilling and development efforts always modify reserves estimates. Added information can substantially change the original estimates if the basic geology or reservoir characteristics change over the area.

It should be noted that economic evaluations enter the picture. It is entirely possible that oil can be located, but declared 'non economic' because the cost of recovering the oil would exceed its market value.

Oil is a tough business.

Mother Nature never reveals her secrets easily. That is job security for geosciences professionals, such as geologists and geophysicists. Larger companies like Shell, Exxon Mobil, and Saudi Aramco are noted for their technical expertise, patience and ability to manage large development projects. They are also less likely to exaggerate reserves estimates. However, all companies have experienced surprises when development and new technology start to reveal the true geology and new economics of a field.

Investors should look for oil and gas company performance based on their ability to replace produced oil and gas with new reserves. To review a few examples, proved oil & gas reserve additions for ExxonMobil totaled 1.7 billion barrels of oil equivalent (boe) in 2003. These reserve additions replaced 105% of reserves produced in 2003. This is the 10th year in a row that the company has more than replaced reserves produced.

Another example is Saudi Aramco, the national oil company of Saudi Arabia. Some US experts have questioned the oil and gas reserves reported by the company. The fact is that Aramco has replaced its produced reserves with new additions every year since Saudi Arabia took it over in 1989. After taking full control from Exxon, Mobil, Chevron and Texaco, the new Saudi Aramco was given a 1989 directive by King Fahd to replace all the oil and gas produced with new reserves. This was the Saudi plan to ensure this national resource would be left to their grandchildren.

Replacing the average daily 2003 production of 8.395 million bbls/day reported by the Oil & Gas Journal, new reserves additions were over 3 billion bbls for the same period. Saudi Aramco accomplished this feat with an aggressive exploration program and a great technology plan. In the meantime, the Saudis developed the 4th largest gas reserves in the world.

So, the best of the best have a goal of replacing produced oil with new reserves. Reserves additions or adjustments will be made every year, but investors should compare the historical performance of production replaced with new reserves. It is also wise to investigate probable and possible reserves, which reflect the success of exploration and development efforts that have not yet been classified as 'proved reserves.'

Each international oil and gas company will have a different standard for publishing proved reserves, so investors need to beware. For example, a successful company may have large probable reserves generated from a single large project, but elect to publish only a small portion as proved reserves. The subjectivity can impact the investor both ways. Finally, technology is important. A good technology plan and an experienced professional staff are required to support long—term performance in the oil field and the development of new oil and gas reserves.

 
The oilfield lexicon
To better understand any discussion of oil reserves, it is necessary to define a few standard terms used in the crude oil business. The unit of measure 'barrel' is actually 42 gallons and the abbreviation is 'bbl'. This US standard was established in the late Nineteenth Century. The story goes that buyers were given an extra two gallons of oil for each forty gallons purchased.

Crude oil quality is defined by its density and sulfur content. Density is given in degrees API (American Petroleum Institute) The higher numbers represent lighter oils and are called light crudes. For example, heavy crude is usually less than API 20 degrees and is very thick and viscous (think about the heaviest molasses you ever saw).

Sweet crude oil has sulfur content less than 0.5%. Sour crude has a maximum sulfur content of 1.99%. Sweet crudes are preferred because they produce high yields of high value products like gasoline, diesel, heating oil and jet fuel.

Generally, specific crude oils are given names, which imply both location and certain characteristics. For example, Brent crude, which is one of the standards on the commodities market, is API 36 degrees with low sulfur content. It would be called 'Light Sweet Crude.'

Dan Berard is our energy correspondent