Royal Dutch Shell Evaluation of Oil Reserves — страница 19

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from the implied variance of call options for Brent Crude Oil traded on International Petroleum Exchange (IPE) on 31.12.2003 according to the prices published in Wall Street Journal using BS option pricing formula. The prices for options and calculations are represented in Exhibit 4.1. Another way to calculate the standard deviation of log oil prices would be to calculate it out of historical data, however this way of calculation would not capture the market expectation regarding the sharp rise of oil prices in the future (if there were such expectation in first hand). The fact that the price for one barrel of Brent went from about $30 in the end of 2003 to about $50 in 2004 and continued to rise throughout 2005 should have made future oil prices more volatile and may represent a

structural break. Therefore, the calculation out of historical data has been found inappropriate in this case. The simulation was then conducted using MS Visual Basic. Oil price for each year is determined based on one thousand iterations where the oil price is calculated out of the simulation output as expected value of lognormal distribution. Results of the simulation are represented in Exhibit 4.2. One can see that the simulation provides gradually increasing oil prices. This feature is particularly important since it is in line with the basic Hotelling Principle, according to which under conditions of perfect competition and certainty net prices of an exhaustible resources like oil and gas should rise overtime at the rate of interest (Litzenberger, Rabinowitz, 1995, p 1520).

Royal Dutch Shell: Evaluation of Oil Reserve Additionally, it should be mentioned that the simulation was conducted for the Brent prices exclusively. This, however, would not be sufficient. Future oil prices should also be attained for other regions in which RDS operates. According to the Group’s annual report it divides its operations into six regions: Europe, Russia and Middle East, Africa, Asia, USA, and other Western Hemisphere. The appropriate oil types for each region are accordingly Brent, Urals, Bonny, Tapis and WTI. For the Western Hemisphere, there is no active market for any particular type of oil, so the prices for this region were assumed to be equal to the prices of Urals. As it has been mentioned before, the price for Brent was set to be a price kernel,

whereas the prices of oil for other regions are calculated according to the prices ratio in the end of 2003. So, the implicit assumption is made here that the ratio of prices for different types of oil will remain unchanged in the long run. This is a very reasonable assumption since the price for oil is determined by its chemical characteristics, which are not expected to change. The calculations are represented in Exhibit 4.3. After the prices for oil are set, it is possible to construct the estimation of future free cash flow produced by the oil reserves. As the first step, one should simulate the production schedule for existing reserves or in other words, how much the reserves will produce each year. As it was mentioned earlier, information about the speed of production is

not included in any of the Group’s public reports; therefore, several assumptions should be made in order to simulate it. First, let us take the assumption that all proved developed reserves should be lifted by the end of 2024 and all the developed + undeveloped proved reserves should be lifted by the end of 2034. This gives the span for production schedule. Next, assumption is to be taken that an overall oil production will not change and will stay at the level of 2003 close to 1400 million barrels of oil equivalent (see Exhibit 2.2 for details). This assumption may seem to be controversial, yet there are several indications that support it. First of all the company management estimates production until the year 2006 to be in the range of 3.5-3.8 mboe per day, which gives

the yearly production of oil and gas between 1300 and 1400 mboe, so the management is not expecting any growth of production in the coming years (RDS Group: Regaining Upstream Strengths, 2004). This is also supported by company’s statistics that shows that after the production had been increasing until 2002 it actually came down in 2003 from 3.96 mboe/d to 3.86 mboe/d and no recovery in production is expected in the coming years (Royal Dutch Petroleum: Annual Royal Dutch Shell: Evaluation of Oil Reserve Report 2003, p 18). Poor data on new reserves discovery also makes it harder for RDS to increase production sometimes in the near future. Actually, the company was already producing more than it discovers in the last years and further decrease in RRR might be very negative