Реферат: Royal Dutch Shell: Evaluation of Oil Reserves
Royal Dutch Shell: Evaluation of OilReserves
To obtain the degree Master of Science in Economics and Management
School of Business and Economics Humboldt University of Berlin
(Matriculation Number 188623)
Prof. Ernst Maug, Ph.D.
Berlin, July 26, 2005Abstract… 3Oil Industry and RDS Group… 4Unification of Royal Dutch and Shell… 8Summary of Chapter One… 10Legal Framework for Oil Reserves Reporting… 12Legal Regulations and Definitions of Oil Reserves… 12Standardized Cash Flow Calculation under the SEC and FASB Rules… 19Mis-presentation and Restatement of Oil Reserves by Shell Management..............21Summary of Chapter Two… 24Reserves Restatement – Event Study… 25Estimation of Reserves Restated Amount… 26Estimation of Market Capitalization Discount for Parental Companies… 30Event Study Results… 33Estimation of Oil Reserves Value with Own Calculations… 35Calculation Using DCF Methodology… 36Calculation Using Real Options Methodology… 44Calculation Results… 49Conclusion… 50References… 51Appendix… 54
In the beginning of 2004, Royal Dutch/Shell group announced that it reduces the quantity of its proved oil and gas reserves. This announcement was the beginning of the largest accounting scandals in history of oil and gas industry. This event had some very negative consequences for Royal Dutch /Shell and for oil industry in general, but in the same time it represents a brilliant and in some sense unique opportunity to assess the fair value that market grants to oil and gas reserves of an actively traded company. This is also a good opportunity to try to replicate the calculations that the market participants would make in order to arrive to the conclusion about the fair value of reserves. Later, it would be possible to compare these calculations with the fair value observed on the market. This paper will consist of four chapters. In the first chapter, some background will be given on what meaning reserves restatement could have for the group and for the oil industry as a whole. In addition, the overview will be given regarding the consequences of the scandal for corporate structure of Royal Dutch/Shell. The second chapter will deal with the issues of legal framework for reporting of oil reserves. It will provide an overview on what stands behind the figures of proved oil reserves (that were restated during the above mentioned scandal) and how this figures different from the ones that market participants would take into account. Furthermore, there will be a discussion regarding other figures on company’s annual report related to oil and gas reserves and that can be further utilized for fair value calculation. In the third chapter, event study will be represented. The aim of this event study would be calculation of fair value observed on the free market using the conclusions of previous chapter Finally, the fourth chapter will be dedicated to own calculations aiming at replication of the fair value of oil and gas reserves observed on the market. The calculations will be made using discounted cash flow methodology and real options methodology. As the conclusion of this paper the assessment will be made on how well do different calculations methods can predict the fair value for oil and gas reserves (if at all) and what are the possible factors that influence the quality of this estimation For the sake of convenience Royal Dutch/Shell Group and parental companies will be defined simply as RDS or Shell as well as word “oil” will de used both for oil and gas. All the figures related to oil and gas reserves (unless mentioned otherwise) represent measure of so called barrels oil equivalent (boe), where 5800 cubic feet of gas equal 1 barrel of oil
1 Royal Dutch Shell Group: Background Information
On May 28, 2002 sir Philip Watts, then chairman of the Comity of Managing Directors (CMD) at Royal Dutch Shell Group wrote e-mail to the CEO of Exploration and Production Unit (EP) in the Group Mr. van de Vijver, which said: “You will be bringing the issue to CMD shortly. I do hope that this review will include consideration of all ways and means of achieving more than 100% (reserves replacement ratio) in 2002. To mix metaphors considering the whole spectrum of possibilities and leaving no stone unturned” This e-mail gives a good illustration of the aggressive policy that was undertaken in RDS in order to meet its external promises regarding reserves replacement ratio (RRR) or in other words, the ratio of discovered reserves to production. In fact, the problems did not start in 2002. Ever since Mr. van de Vijver succeeded the position of EP CEO from sir Philip in 2001, he has noticed that the actual situation with oil discoveries is not as rosy and optimistic as it seems to be from company’s reports (Davis Polk & Wardwell, 2005). This aggressive policy to push as much oil reserves into balance sheet as possible was one of the reasons behind the oil reserves scandal that struck one of the oldest and well-established oil companies in the world in the beginning of 2004. This chapter will give some background on Shell’s place in world oil industry. This information will be useful in understanding the scale of recent scandal for oil industry and Shell itself. Afterwards some information will be given on the recent unification announcement, which is also may be regarded as one of the scandal outcomes.
1.1 Oil Industry and RDS Group
Royal Dutch Shell Group of Companies is one of the biggest vertically integrated oil groups in the world that has about 119 thousand employees in 145 countries. Shell unifies practically all the stages that involve energy and chemicals production in its five units: EP, Gas and Power, Oil Products, Chemicals and Renewable Energy. Group’s activities involve marketing, transporting and trading oil and gas; providing oil products for industrial uses including fuel and lubricant for ships and planes; generating electricity, including wind power, and producing solar panels; producing petrochemicals that are used for plastics, coatings and detergents; developing technology for hydrogen vehicles (RDS: The Shell Report, 2003).
The split of company revenues between different units in 2003 is shown in Figure 1.1:
/>EP 9%/>/>Power />Oil Products />Chemicals
(Source: RDS Form F-20) As in this paper the main attention will be drawn to the oil reserves, the figures in interest will be those of EP unit. The figure shows that the unit provides some 14% of revenues and it is second most important unit after Oil Products. So, the performance of this unit is of importance for the overall company performance. The picture becomes even clearer as one looks at company’s assets distribution in Figure 1.2:
/>Power 30%/>Oil Products />Chemicals
(Source: RDS Form F-20) The figure shows that most of RDS’ assets (57%) are concentrated in EP unit. As most of these assets are attributed to oil and gas reserves, it is easy to imagine that any change in reserves will have immediate and substantial consequences on company’s balance sheet. Especially when the restatement involves restatement of about a third of the existing oil and gas reserves as it was in case of the latest scandal.
The consequences of the scandal were also reasonably large for the oil industry as a whole. Although, Shell only produced some 3% of world oil and 3.5% of oil gas, it held some 9% of proved oil reserves in 2003 (BP, 2004). Given the degree of dispersion in the industry this is still one of the biggest oil producers in the world. There is another reason why restatement of oil reserves by Shell had consequences for the oil industry. To see this one should look at the data in Table 1.1:CompanyProduction (mbbl) (oil only)CompanyProved Reserves (mbbl) (oil only)Saudi Arabian Oil3055Saudi Arabian Oil259300National Iranian Oil1385Iraq National Oil112600Petroleos Mexicanos1299National Iranian Oil99060Petroleos Venezuela1193Kuwait Petroleum96500RDS 810Abu Dhabi Oil92200Nigerian Petroleum766Petroleos Venezuela77783PetroChina763Oil Corp Libya29500Kuwait Petroleum745Petroleos Mexicanos25425Iraq National Oil715Nigerian Petroleum24000BP677Qatar Petroleum15207Lukoil570Lukoil14243Abu Dhabi Oil568PetroChina10959TotalFinaElf530Yukos9630Oil Corp Libya496RDS 9469Petroleo Brasileiro485Sonatrach9200Pertamina438Petroleo Brasileiro7749Yukos362BP7217Petroleum Dev. Oman329ToalFinaElf6961ENI312Petroleum Dev. Oman5524Sonatrach285Sonangol5412
(Source: OGJ, 2003) The table shows top 20 oil producing companies and reserves leaders in 2003. One can see that the number of Western companies in the list is rather limited and that in both cases RDS is ranked one of the biggest among Western or Russian oil companies, which are precisely the companies listed on the stock exchanges and included in the major indexes. Thought RDS is not the market capitalization leader, restatement of its reserves would most probably have an influence on any market index constructed out of oil companies’ stocks. This fact will have its implication, as the event study will be conducted in Chapter
3. It can be added that before the restatement Shell’s reserves life ratio (i.e. quantity of reserves divided by yearly production) was about 15 years, which is just slightly smaller than 17, the average number for Europe and Eurasia, where most of Group’s reserves and production are concentrated. After the restatement, the ratio fell to only 10, which puts Shell into disadvantaged position in comparison to other companies in the industry (BP,
Royal Dutch Shell: Evaluation of Oil Reserve 2004). Just for comparison, one can take a look on Table 1.2, where the reserve life in different world regions is summarized:Region N.AmericaEurasiaM.EastAfricaS.AmericaAsia Pacif.Reserves Life 1217883341.516
(Source: BP, 2004) The huge numbers of Middle East and South America can rather be ignored as most of the reserves there are owned by the local state run companies, but it still does not make the overall position of Shell in comparison to industry average much better.
Now as the degree to which the restatement of oil reserves could influence the standing of RDS and the oil industry as the whole becomes clearer, let us take the first look at one of the issues directly affected by this restatement, namely at Shell’s ownership structure. To do this one should first turn to the group’s history. The partnership of Royal Dutch and Shell dates back to 1907, when sir Marcus Samuel, than Chairman of deeply indebted Shell Transport and Trading Company, stuck the deal with Royal Dutch Oil Company in desperate effort to save the company from bankruptcy. According to this deal, two companies would share risks and benefits of the oil projects at Caspian Sea coast that were owned by Shell and some smaller Far Eastern oil projects that were owned by Royal Dutch. The cut of this deal was 60:40 in favor of Royal Dutch, the cut that remained throughout the 100 years history of the Group. Back then, many regarded this deal as a merger, however it was not thru. Both companies remained independent and continued that way until recently. So, definition that is more appropriate would be partnership or alliance. In the early 20th century, Group started aggressive expansion through acquisitions in Europe, Africa and the Americas, which continued also in interwar period, when Shell entered into chemicals production. All in all, after the second World War RDS became a global integrated oil and chemicals company, thought its assets have been confiscated twice during the wars. Following the war Shell expanded into transport and refinery businesses. In the sixties, as world oil output began to rise dramatically Shell was one of the leading oil companies supplying about one seventh of the world demand for oil In the 70s, just before the recession started, Shell made major oil and gas discoveries in the North Sea, just off the coast of Scotland. This discovery could not come any more on time, since at that time oil prices surged and more and more people turned to natural gas, which accounted to 15% of Europe’s energy demand at that time. With the lower oil prices in 90s, Shell concentrated on its core businesses — mainly oil, gas and chemicals. The group also started to look at sustainable energy solution and renewable energy sources (Howarth, 1997). Although, Shell for long have been regarded as the single company, in fact throughout its history it remained to be a partnership and consisted until recently of two separate companies, had two board of directors, two CEOs as well as two separate listings on Amsterdam, London, New York and other stock exchanges. The corporate structure of RDS can be illustrated by Figure 1.3:/>
(Source: RDS: F-20 Form, 2003) As was mentioned above, the complex structure of ownership that is represented in the figure existed in 2003 due to historical reasons. This structure, by no doubts did not add any clarity for the investors and in fact contributed to the ambiguous internal reporting system that existed in Shell until recently and that allowed group’s management to boost the numbers of proved reserves without proper control. In order to build a more reliable corporate structure, RDS group took several steps, the latest of which was the unification of parental companies into single Royal Dutch Shell PLC.
1.2 Unification of Royal Dutch and Shell
As it was mentioned the ambiguous corporate structure was one of the causes for the mis-presentation of oil reserves resulted in the later scandal. Therefore, already in the
Royal Dutch Shell: Evaluation of Oil Reserve beginning of 2004 the boards of two parental companies announced that they are planning to revive the long planed unification of Royal Dutch Shell into one company. This was made in order to boost its corporate image and to regain investor’s confidence in RDS. On 28 October 2004, the Royal Dutch Boards and the Shell Transport Board announced that they had unanimously agreed, in principle, to propose to their shareholders the unification of Royal Dutch and Shell Transport under a single parent company, Royal Dutch Shell. And than on 19 May 2005 the companies announced the final proposal for the unification. Among the reasons for unification as announced by companies’ management were increased clarity and simplicity of governance, management efficiency, increased accountability and flexibility in issuing equity and debt. Management proposed clearer and simpler governance structure. This will include one-tier directors board and a simplified senior management structure with a single non-executive Chairman, a single Chief Executive and clear lines of authority. Increased efficiency of decision-making and management processes generally, including through the elimination of duplication and the centralization of functions. Clear lines of authority and accountability, with the Executive Committee reporting through the Chief Executive to a single board with a single non-executive Chairman was expected to improve the accountability of the board and management to all shareholders. A single publicly traded entity is expected to facilitate equity and debt issuances, including on an SEC-registered basis (RDS, 2005). After the unification, the former parental companies are to become subsidiaries. New company will be incorporated in UK and will have a head office in the Netherlands for tax purposes. As it concerns the shareholders, the shares of Royal Dutch and Shell will be exchanged in proportions as shown in Table 1.3:Royal Dutch Share traded in Amsterdam 2 “A” Shares of RDS Royal Dutch Share traded in New York1 “A” ADR of RDSShell Ordinary Share0.287333066 “B” Shares of RDSShell ADR0.861999198 “B” ADRs of RDS
(Source: RDS, 2005) Although, there still will be two types of shares, the trading will become much clearer, since instead of 2 billion shares of Royal Dutch with a nominal value of 0.56 EUR and 9.6 billion shares of Shell with nominal value of 0.25GBP, both “A” and “B” will have nominal value of 0.07 EUR. Both kinds of shares will be traded on Euronext in
Amsterdam and in London. American depository receipts (ADRs) will include two shares and will be traded in New York. As previously, the share of “A” stocks in the new company will be 60% and share of “B” stocks 40%. Also, the dividend policy of RDS will become clearer, as all the dividends will be announced in Euros. In Chapter 3, it will be shown that previous dividend policy lead to inequality between Royal Dutch and Shell shareholders. Finally, the event day of unification was July 20, 2005. On that day, RDS was floated on all three bourses and this ended almost hundred-year history of Royal Dutch/Shell partnership. As the result of unification, new company becomes the biggest oil and gas enterprise on FTSE index ahead of BP and one of the biggest companies in FTSE 100 index. The overall reaction of markets on the unification was positive. The shares of RD and Shell went up after the announcement and short before the event day. Still it is difficult to filter out markets reaction, since one day before the unification, RDS announced that the costs of oil exploration for one of its projects in Russia would be substantially higher than expected, which pushed the stocks down.
1.3 Summary of Chapter One
In this chapter, several consequences of the recent oil reserves scandal at RDS were discussed. It was shown that oil and gas exploration and production is meaningfully large line of RDS’ business both in terms of revenues and assets. It is clear that any asset and income restatement in Exploration and Production unit will have immediate large-scale consequences on the stock price of parental companies in RDS Group. It was also shown that Royal Dutch Shell was one of the leading oil companies in the world, though its share in oil and gas production constituted only about 3% in 2003. Therefore, the restatement of oil reserves by RDS had also consequences for the oil industry as the whole. The standing of RDS in comparison to industry average deteriorated on the restatement. It was shown that “reserves life” measure of RDS went down to 10 years, which is significantly lower than world and regional average. Additionally, one of the possible sources of problems that lead to reserves restatement was discussed, namely, the corporate structure of RDS. Then the consequences of the restatement for the corporate structure were presented. Partially due to the scale of the scandal that was generated by the oil reserves restatement, management of parental companies decided to push forward with the changes in group’s corporate structure and unified two parental companies. In the following chapters, the further consequences of the scandal will be represented and evaluated.
2. Legal Framework for Oil Reserves Reporting
Before one can continue with the analysis of oil reserves restatement assessment of reserves’ value, it would be important to understand what stands behind the figures and values restated in 2004. It is vital to remember that during the scandal company announced the restatement of proved oil reserves. This chapter is dealing with the question of whether proved reserves is the same as overall reserves and what are the figures that are used by market participants and that should be used in for the analysis in this paper. In the first and second section of this chapter, the legal framework will be provided for two key figures that will be used in the following chapters:
-Quantity of oil reserves reported by company
-Value of oil reserves on company’s balance sheet In the third section of this chapter, the assessment will be made on what role might have the existing legal framework in the reserves mis-presentation in case of RDS. This chapter is aimed at explaining how the present reserves disclosure system works, what are the number reported by energy and oil companies and what is degree of freedom given to the company in reporting of the reserves. Later the particular misuse of the existing rules by Shell will be discussed as well as the consequences of the oil reserves scandal in Royal Dutch Shell.
2.1. Legal Regulations and Definitions of Oil Reserves
The way in which management calculates its oil reserves’ value and quantity may be not totally transparent and understandable for investors, which in turn adds to the risk and uncertainty in the evaluation of oil producing companies in general and Shell in particular. Unlike most of the other figures on the company’s balance sheet the value of oil reserves is not based on the historical value or on the value observed on the free active market. The oil reserves as well as gas reserves are represented based on the volume of hydrocarbons companies believe they can produce with reasonable certainty based on the scientific and engineering analysis (SEC, Regulations §210.4-10 1978). That includes both evaluation of the quantity and the dollar value of the reserves. In fact, while aiming at the reasonable certainty and greater comparability of oil reserves publicly reported by the oil companies, current system of reporting contradicts the reporting standards that are accepted by industry and is rather confusing for the investors. The main problem with the reporting system as it exists today might be the fact that it omits large part of the oil reserves in the company, namely the reserves that have not yet received
Royal Dutch Shell: Evaluation of Oil Reserve reasonably certain geological approval and therefore booked as probable or possible. These reserves are in average 50% larger than the ones reported by the oil companies and therefore constitute the most of the company’s potential oil production in the future (Bentley, 2002). The problems in the current system of accounting for oil and other mineral resources might be tracked down to the time it has been developed in 1978 and approved by US Congress. So called “System 1978” that has been later implemented through rules and guide lines built up by Security and Exchange Commission as well as through the accounting standards of FASB was originally created without having the investors and other market participants as the primer “client” in mind. The Congress created the requirements for reserves disclosure primary targeting the national security and energy security purposes (CERA, 2005). As one is trying to review the evaluation methods and representation patterns for oil reserves that are generally accepted in the industry and recommended by the regulatory authority like SEC, one should perhaps start with the most basic definition, that is definition for reserves probability. On one hand, oil reserves are nothing more that another type of company’s inventories, but unlike the inventories that can be precisely calculated, oil reserves are uncertain. Oil and gas reserves represent the cumulative production of a field until it is completely depleted. Production depends mainly on the volume in place (net pay and area), the geology of the reservoir (porosity, permeability), the physics (engineering) of the fluids (pressure, temperature, saturation, density and viscosity), the development scheme (wells producers and injectors), and the economics (cost and price). The geological uncertainty adds to the economic uncertainties. These uncertainties can only be represented by the range of probabilities. The problem is that investors do not like the uncertainty. Therefore, the guidelines of “reasonable certainty” were issued by SEC in 1978 according to which only proved reserves should be represented. The problem is that everyone can interpret “reasonable certainty” in its own way and it can vary from 51% (more probable than not) to 99% (Laherrere, 2004, p1). Right now, there are as many reserves definitions and evaluation techniques as there are the parties involved in the process. Namely each oil company, each security commission or government department tends to use its own definition for the reserves. This can certainly cause an enormous chaos and lack of comparability between different evaluations issued by different bodies and above all makes the definition of reserves not that certain as it was intended to be initially.
Royal Dutch Shell: Evaluation of Oil Reserve Still there are two major groups of definition that can be detected and that are used today by most of the players on the oil market for the financial analysis and for technical analysis of the reserves. These are deterministic and probabilistic definitions as they are represented in Table 2.1:Deterministic Approach Probabilistic Approach Proved (P1) Reasonable certainty Proved (1P) At least 90% Probability Probable (P2) More likely than not Proved + Probable (2P) At least 50% Probability Possible (P3) Less likely than probable Proved + Probable + Possible (3P) At least 10% Probability
(Source: Harrell Ryder Scott 24 Oct. 2002 in Laherrere 2004)
Method is called deterministic if a single “best estimate” of reserves is made based on known geological, engineering, and economic data. The method of estimation is called probabilistic when the known geological, engineering, and economic data are used to generate a range of estimates and their associated probabilities. Many oil companies base their investments on a most likely case (deterministic), but only after gaining a thorough understanding of the range of reserves and associated probabilities (i.e., probabilistic background). Indeed, the sizing of equipment and facilities to produce oil and gas generally has to be specified and does not allow for a wide range of possible outcomes. Nevertheless, the decisions made by oil companies are often based on a thorough understanding of probabilistic reserves in the first instance (CERA, 2005. p 13). The latest and the most widely accepted version of probabilistic approach definition was issued by the Society of Petroleum Engineers and World Petroleum Council in 1997. These definitions represent a loose compromise between the probabilistic approach used in the industry and more conservative deterministic approach accepted by US Security and Exchange Commission. In order to understand what is standing behind the definitions proposed by the industry and by SEC and to have a clearer picture of the expectations of the capital markets and the investors about the reserves booked under each category let us discuss the explanations provided by SEC for reserves booking. The existing SEC guidelines were first issued in 1978 under the regulations of financial accounting and reporting for oil and gas producing activities pursuant to the federal securities laws and the Energy Policy and Conservation Act of 1975 or so called “Rule 4
10” and later supplemented by various explanatory guidelines, the latest of which were issued in 2001. The reserves to be reported under the Rule 4-10 are the reserves that follow the definition of proved reserves: “Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. …Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test… …Estimates of proved reserves do not include: (A) oil that may become available from known reservoirs but is classified separately as «indicated additional reserves»; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
(C)crude oil, natural gas, and natural gas liquids, that may occur in un-drilled prospects…”(SEC Regulations §210.4-10, 1978) “Reasonable certainty” is explained by SEC as the concept, which implies that, as more technical data will be available for the particular reserves, the possibility of rescaling reserves upwards is significantly higher than the possibility of the downward rescaling (SEC Financial Reporting and Interpretation Guidelines §II F- 3, 2001). In other words SEC will require reporting a single most probable value of reserves under the existing geological data and the current oil prices, i.e. the quantity that is to be recoverable given existing market conditions and the information provided by the by the company’s oil engineers (Laherrere, 2004, p4 sqq). The quality of data provided by the company and the standards under which it is provided will be discussed later as the special case of Shell will be assessed. Furthermore, SEC rules are defining two subdivisions of the proved reserves, namely developed and undeveloped proved reserves. Proved developedreserves are defined as follows: “Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods…”. Whereas proved undevelopedreserves according to SEC definition are: ”Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on un-drilled acreage, or from existing wells where a relatively major expenditure is required for re-completion. Reserves on un-drilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled…” (SEC Regulations §210.4-10, 1978) As it was mentioned earlier the existence of proved oil reserves will anyway require an economical viability of the reserves, therefore, from the SEC point of view this sub-definition should not add an uncertainty to the undeveloped proved reserves, but rather should indicate that an additional capital expenditure is needed in order to put it in to production (SEC Financial Reporting and Interpretation Guidelines §II F- 3, 2001). To conclude, one can say that instead of providing the whole range of probability SEC rules are aiming on presenting a single best number. This approach does not provide the investors with the comprehensive picture of the oil reserves probabilities. This in turn, makes it much harder for the investors to assess the one single number of their interest, namely the median or expected oil reserves. To tackle the problem of the information insufficiently so-called probabilistic definitions were accepted by the industry. Although, these definitions are not accepted for the public reporting (at least not in US and EU), they are widely accepted among professionals and are normally used for reporting both by the oil engineers in the companies and by the independent oil consultants (SPE Oil Reserves Definition, 1997; CERA, 2005, p 14 sq) In the probabilistic approach, oil reserves are broke down in to three categories: Proved, Probable and Possible. Proved reserves are defined just as they are under the SEC definition – the reserves with reasonable certainty and commercially recoverable or the amount of oil that can be extracted with the certainty of 90%. Although, the definitions are confusingly close, they are not identical, as the deterministic definition of proved reserves is widely interpreted as a single best prediction, it does not always correspond to 90% (OGJ, 2003, p31) The unproved reserves imply that technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. Unproved reserves may be further classified as probable reserves and possible reserves. For probable reserves it is required that, there is at least 50% probability that the reserves eventually recovered will be equal or exceed the total quantity of proved and probable reserves. Generally speaking the reserves that are normally included into this category are the reserves, which are expected to be proved in the coming years, by normal drilling procedure, reserves in formation and incremental reserves that require further evaluation and all in all the reserves that require further treatment Possible reserves are ones, for which the technical analysis suggests that they are more likely not to be recovered or in terms of the probabilistic approach the reserves, for which there is at least 10% probability that the amount of oil eventually recovered will be equal or exceed the total quantity of proved, probable and possible reserves. The reserves under this category are generally those based on geological interpretations and can possibly exist beyond the areas classified as probable. These reserves require further geological data gathering (SPE Oil Reserves Definition, 1997). The difference between two approaches would be better understood, if illustrated graphically. When the technical and geological analysis of an oil field is made, the probability distribution of oil reserves is usually assumed to be lognormal. This assumption is rather common for the industry, yet it is not the only one possible (O’Connor, 2000 p3 sq; Campbell et al, 2003 p1 sqq; Laherrere, 2004, p 4 sqq). In other words, this assumption implies that at the certain stage of an oil extraction project management already knows that particular oil field or oil producing region posses the reserves that are enough for commercial production. Still the precise quantity of the reserves remains uncertain and company’s engineers use the Monte-Carlo approach in order to model the distribution of reserves (Thanh, SPE, 2002, p 2). As the companies reporting under the deterministic SEC approach often interpret the proved reserves definition to be the most likely (mode) value of the reserves (SEC Financial Reporting and Interpretation Guidelines §II F- 3, 2001), under the lognormal distribution, companies would report the reserves at 60-65% probability as the proved ones (Laherrere, 2004, p 4). Reserves reported under this approach are shown in Figure
Proved Reserves In the Figure2.2, probabilistic approach is illustrated under the same assumption of the
lognormal reserves distribution.
Proved Probable Possible
As one can see, although the names are the same, the values granted to the proved reserves under different approaches are not identical. In the deterministic approach prescribed by SEC and used by Shell the probable reserves do not represent reserves recovered under 90% probability and in the same time they do not represent the mean reserves (P50 = Proved + Probable under the probabilistic approach), which could signal the expected volumes of the oil reserves lifted. The general problem with the oil reserves definition today is that the SEC principles, which were created in the 70’s mainly for the North American oil reserves, are used nowadays for almost 40% of world oil production and 10% of the reserves (a majority of which is not held by US companies), due to the fact that in the last 20 years SEC has virtually became the world regulator. Although, SEC’s underlying principle of “reasonable certainty” for defining proved reserves remains robust, it has become increasingly difficult for companies to reconcile the SEC’s interpretation of this principle with how the companies themselves are actually working. This has created an environment in which data disclosed in compliance with the regulations may not be serving the needs of investors and is not providing the appropriate information to make informed investment decisions (CERA, 2005, p 4 sqq). To conclude this, one can say that when dealing with company’s oil reserves, one is in fact dealing with random log normally distributed value. In order to provide the complete information regarding this variable, company should have provided the complete density function or at least some key points of the distribution as it does in internal reports. Instead, current reporting system tries to represent this random distribution as a single figure, which in turn makes company to conduct two separate reporting systems and leads to confusion and sometimes to misrepresentations.
2.2 Standardized Cash Flow Calculation under the SEC and FASB Rules.
Now let us focus on another estimation that the companies reporting under SEC regulations are obliged to represent on their annual report, namely the cash flow that the existing oil reserves are expected to produce in the future. The requirement of standardized measure of cash flow is stated in the SEC Rule 4-10 and the guidelines are represented in Financial Accounting Standards Board Standard 69. In its guidelines, FASB sticks with the conservative approach in the general spirit of the SEC reporting strategy for oil reserves. The principal rules on how the standardized measure of discounted net cash flow from producing proved oil and gas (SMOG) is calculated as well as the reasoning behind these rules are represented by FASB back in 1982 and remained practically unchanged since than. A standardized measure of discounted future net cash flows relating primary to an enterprise's interests in proved oil and gas reserves shall be disclosed as of the end of the year in accordance with the principles and guidelines stated in FAS 69. This mash flow measure should provide the following information to the investors:a. Future cash inflows. These shall be computed by applying year-end prices of oil and gas relating to the enterprise's proved reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation or in other words assuming the continuation of the present conditions principle. c.Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, less the tax basis of the properties involved. d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount (FASB Standard 69, 1981).
In other words, FASB requires from the companies to reproduce some features of the NPV calculation and omits other features. In that way, oil reserves lifted in the future are to be the same as the oil market prices in the end of the year. The same assumption is used for the operational and development expenditures in the future and in the same time discount factor is to be applied. One of the obvious factors that make SMOG-approach difficult to use both for the investors and for the companies is the requirement to make the calculation in accordance with end-year prices. As we know, oil commodity prices are subject to fluctuations and speculations nowadays and in many cases, the price on December 31st may not reflect fully the actual average market price for oil. The problem is that the FASB standard was issued in 1981, year before the trading of oil begun on NYMEX. Before that, prices were partly regulated by national governments and were normally posted by buyers, so that not much of the volatility was experienced (CERA, 2005, p 20). Although, deregulation of oil markets made it another tradable commodity with highly volatile prices, yet the rules remained unchanged. The inconsistencies in the SMOG approach are well recognized and explained by the FASB itself. It is admitted that this measure cannot provide the investors with the present value of the oil reserves, but rather is aimed on providing the standardized measurement. This measure should be a compromise between the need to give a complete information to the investors and the industry constrains that would have to put too much time and effort into the SMOG calculation if any estimations were involved in the measurement (FASB Standard 69, 1981). Indeed, the fact that SMOG does not give companies’ management too many degrees of freedom in the calculation process enables the investors to make their own calculation and compare among different companies in the industry. In this study, SMOG would be functional for the calculations in Chapter 4, where the estimation of future operational and exploration expenditures as well as the estimation of future income taxes will be required. At December 31st 2003, the standardized measure of net cash flow of Royal Dutch Shell Group of Companies was $53.8 billion and the future inflow from oil and gas sales were $281.9 billion that is based on the year-end oil price of $26.66/bbl and natural gas prices of 17.30/boe. Full statement of Standardized Discounted Future Net Cash Flow can be found in Exhibit 2.1. The above-mentioned figures clearly cannot be seen as a meaningful estimate of the value of company’s oil reserves for several reasons. First, it is impossible to determine the production schedule of the company. Second, as it is required by FASB the oil prices are set to the value in the end of 2003. Third, the discounting is made with 10% rate, which should represent the weighted average cost of capital at Royal Dutch Shell. It will be shown in Chapter 4 that this measure is inappropriate and that Rwacc for RDS should be set at about 7.2%. Although the figures themselves are hardly reliable, one can take it as a starting point for the further calculations. Also, in the Chapter 4 SMOG report will be used in order to determine the tax rate and operational margins for oil and gas production in different regions. Now, after the picture of how the reporting is conducted is more or less clear, let us move further and see what role did the complication of the reporting played in the recent oil resources scandal by RDS.
2.3 Mis-presentation and Restatement of Oil Reserves by Shell Management
As it was shown in the previous sections, the way in which company reports quantity and value of its oil reserves is rather complex and hardly provides the investors with the information that is to any extend close to the reality. Eventually, this should have resulted in a major misuse of the accounting standards and that is exactly what happened to RDS Group’s oil reserves. Between January 9 and April 19, 2004, Shell announced the reclassification of 4.47 billion barrels of oil equivalent, or approximately 23% of previously reported “proved reserves,” because they did not correspond to the definition of applicable law as it is required by SEC Rule 4-10 therefore the large quantity of reserves had to be stated as “un-proved” and in accordance to the SEC and FASB rules have to be virtually excluded from the company’s balance sheet. Shell also announced a reduction in its Reserves Replacement Ratio. The Reserve Replacement Ratio (RRR) is probably one most significant figure in the oil industry, which is serving as a basis of long run analysis for the oil and gas companies. This is a ratio of oil production in any particular period to the quantity of new oil reserves discovered and booked as proved. In other words the ratio is aimed to measure whether the company is discovering less resources than it produces and eventually will have to reduce or even shut down the production (this is in case RRR is less than 100%) or will be able to sustain or increase the level of production in the long run (this is in case RRR is equal or greater than 100%)
Although, restatement of oil reserves is a normal practice in the oil companies, in case of Shell this restatement was not conducted on time and this fact draws the attention of the stakeholders. Shell’s overstatement of proved reserves, and its delay in correcting the overstatement, resulted from its desire to create and maintain the appearance of a strong RRR. Another reason was the failure of its internal reserves estimation and reporting guidelines to conform to applicable regulations. And finally, the delay in restatement was result of the lack of effective internal controls over the reserves estimation and reporting processes (as it was discussed in Chapter 1, Shell’s corporate structure was not particularly reliable). In the interest of protecting the public against misleading financial disclosures by public companies, the SEC Security and Exchange Commission filed the complain against Royal Dutch Shell Group (SEC v. Royal Dutch Petroleum Co., et al., 2004). As a result of the scandal, reserves were downward restated for 2003 and also reserves of 2002 and 2001 were backwardly amended. The investigation by SEC and by the private adviser company Davis Polk & Wardwell that was later initiated by Shell itself found that although since the 1970’s, Shell has utilized a series of comprehensive internal guidelines for the estimation and reporting of oil and gas resources, including its proved reserves, these guidelines failed to conform to the requirements of Rule 4-10, in a number of significant ways. Namely, the guidelines of Shell were originally designed and maintained to serve the probabilistic approach for reserves booking, which is used in Shell for internal reporting. These guidelines failed to reproduce correct and reliable basis for reporting under deterministic approach. As a result, in some cases the P50 reserves (mean or proved + possible reserves) were included into the proved reserves under SEC definition. Shell also did not implement its own guidelines properly due to the lack of internal controls. Shell failed in several respects to implement and maintain internal controls sufficient to provide reasonable assurance that it was estimating and reporting proved reserves accurately and in compliance with applicable requirements. These failures arose in the first instance from inadequate training and supervision of the operating unit personnel responsible for estimating and reporting proved reserves. The reporting units in Shell were highly decentralized, which in turn made the normal flow of technical and contractual data more difficult. The deficiencies in the internal reserves audit function played additional negative role in the case. The proper internal audit of oil reserves in Shell was either poorly financed or virtually inexistent (SEC v. Royal Dutch Petroleum Co., et al., 2004; Davis Polk & Wardwell, 2005). All this resulted in the public scandal after which Shell had to make a wide scale restatement of its oil and gas reserves. The restatement concerned some of the major oil and gas reserves of Shell, namely the reserves in Australia, Oman and Nigeria in the first place. Also, other oil fields of Shell suffered from restatement, so that overall restatement was divided fairly among the production facilities of RDS around the globe. The summarized information about the backward restatement of proved reserves is represented in Table 2.2:/>
(Source: SEC v. Royal Dutch Petroleum Co., et al., 2004) As it can be seen from the Table 2.2, the “final” cumulative restatement (that was also included in the annual report for 2003) was 4.47 billion barrels of proved reserves and the company’s management estimated the reduction in $6.6 billion in SMOG report. That gives us an average discounted value for one barrel of oil equivalent of approximately $1.5. For comparison, let us look at the average discounted net profit that is estimated by management from one barrel of oil. For that purpose, one can use the overall estimations of company’s proved oil and gas reserves that are found in company’s Financial and Operational Information Report for 1999-2003 and that are represented in Exhibit 2.2. According to this measure developed and undeveloped oil and gas reserves of RDS in the end of 2003 after restatement, including company’s interest could be estimated in oil equivalent as approximately 14.3 billion barrels. According to SMOG, the future discounted cash flow that company’s management expects to receive from lifting and selling these reserves is estimated at $53.8 billion. This gives average net discounted revenue of $3.76 per barrel. The reasoning behind this could be the quality as well as other features of the reserves restated. As one can see from the Exhibit 2.2 the proved reserves of RDS are classified as developed and undeveloped. The quantity of developed reserves is 8.6 billion barrels or 60% of the proved reserves, whereas the quantity of undeveloped reserves is only 5.8 billion barrels or some 40% of total proved reserves. On the other hand, restated reserves containing 88% of undeveloped reserves and only 12% of developed reserves. The developed reserves are the ones that are already set to produce oil and for which no major capital expenditures will be required, whereas the undeveloped reserves require additional capital expenditure in order to be produced. That may include additional
Royal Dutch Shell: Evaluation of Oil Reserve expenditures for exploration, costs of lifting facilities set and so on. For these reasons it is obvious that undeveloped reserves would in average bring lower cash flow to the company and therefore the reduction of the reserves value in this case was significantly lower than it would be in case if the majority of restated