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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn this paper, the production sharing contract (PSC) terms and conditions are incorporated into a decision-making model of hydrocarbon production. Based on input parameters such as oilfield size, prices, exploration, development and operating costs, decline rates, cost recovery methods and profit oil split, the model was used to evaluate best, worst, and most likely scenarios. In each of the scenarios, the oil production rate from the field increases initially up to the maximum efficient production rate, as surface facilities are built, followed by a plateau period of constant production rate and then finally a decline as in typical offshore fields. Using the expected net present value (ENPV) of a project under various technology and financial arrangements, the model performs the summary economics of a scenario based on the pro-forma cash flow analyses. The numerical example for India has been developed to reflect geological, economic, and the recent contractual data as defined in the 1997 New Exploration Licensing Policy (NELP) for PSC agreements. The best and worst cases examine the optimistic and the pessimistic scenarios about the profitability of a project. In the third case (most likely case), probability distributions for various crucial parameters are specified in the model. The model also calculates India's share of economic rent from oil and gas production in these cases.Finally, a sensitivity analysis is performed on parameters which provides insights into mutually beneficial negotiating terms between the government and the multinational corporation.Results indicate that recent PSC terms in India can be attractive to multinational corporation (MNC) investors for medium to large discoveries. Conversely, smaller projects have greater difficulty achieving profitability. The most likely case indicates a modest government take of around 46 percent in India. Sensitivity analyses show that reserve size and production decline are the dominant factors for determining project payout and net present value. In addition, PSC projects in India are less sensitive to factors such as profit oil split and cost recovery oil terms.

As Rate of Reserve Replacement continues to be challenged, International Oil Companies (IOCs) face competition from other IOCs as well as from entrepreneurial national oil companies (NOCs) aggressively looking to develop assets domestically and overseas. A disproportionately large fraction of reserves are controlled by a few NOCs, and downstream resources are similarly pursued by NOCs and IOCs alike. Evaluation of potential countries or regions targeted for reserves replacement objectives must be made based on assessment of key risk factors for mid to long timeframe. Country Risk Assessments for new country or region entry decisions serve as a crucial decision point in determining viability of project or project portfolio from a location perspective, but such assessments typically tend to be time consuming, complex, somewhat subjective, and often do not provide a basis for any objective comparison between candidate countries or regions. Using a matrix of weighted risk factors this model presents a simplified approach for objectively assessing a potential country or region under consideration, and provides a basis for apples-to-apples comparison between shortlisted countries or regions. This approach is applicable to IOCs, NOCs, or Service Companies alike. Based on a relevance-weighted approach this model can assist in quick screening before further due diligence is embarked on. This not only accelerates decision-making for such investment considerations, but also provides input for later detailed project risk management. Introduction The hunger for oil continues to rage, undaunted by ever-climbing crude prices. Today's tight supplies are primarily because of surging world economy and growing demand, particularly in Asia and Middle East. Technological advances have made it possible to explore and exploit resources that were previously beyond reach, or simply uneconomic - but higher cost of development coupled with resource nationalism and regulatory uncertainty by NOCs and host governments have made it harder to bring supplies to market quickly. Amidst the feeding frenzy the reserve replacement challenge gets tougher with each passing day. As easier plays are tapped, the hurdle simply gets raised in terms of geographic, political, energy security, economic, or technical challenges that must be surmounted in order to reach the next barrel of crude. Today's realities appear to be more on management of above-ground risk in developing, transitional and politically unstable countries than managing below-ground risk. Figure 1 shows average annual change in consumption of crude oil and natural gas liquids in major world regions and countries in million of barrels per day. For example; in OECD Europe, oil consumption increased from 13.7 MMbbl/d in 1990 to 15.5 MMbbl/d in 2005 (a net increase of 1.8 MMbbl/d). Oil consumption is expected to increase by only 0.1 MMbbl/d in next 15 years in OECD Europe. On the other hand, in Russia and FSU countries, oil consumption is expected to dramatically increase in next 15 years after a long and continuous decline in consumption levels in these countries. In addition, developing Asia and the Middle East is expected to reshape the future oil market.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis study provides a comprehensive evaluation of the production, reserves and economic potential of natural gas extraction and transportation from Nova Scotia offshore (Sable Island) plays. Newly available information from Canadian Gas Potential Committee (CGPC) and other private data vendors was integrated into a comprehensive Gas Systems Analysis Model (GSAM), which is a gas supply, demand and transportation model developed by the U.S. Department of Energy (DOE).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractReporting of reserves or "reserves booking" is an important issue in reservoir management. Despite this fact it is not practiced in a consistent manner by field operators, royalty owners, the Government, the investing community, and other stakeholders in the oil and gas industry. Furthermore, the Securities and Exchange Commission (SEC) and Financial Accounting Standards Board (FASB) statements on this issue are fairly vague, leaving much to individual interpretation of the rules. This inconsistency in reserves booking is due in part to the lack of a well-defined set of guidelines and is exacerbated by geologic and market uncertainties.In this paper, we investigate approaches to improve reserves booking procedures making use of the 14 th update of NRG Associates database "The Significant Oil and Gas Fields of United States". Data from all the gas fields discovered in the year 1990 were taken to arrive at an average representation of the reserves booking practice. In addition, two fully developed fields in the Rocky Mountain region and the Gulf Coast region were taken to investigate individual field level reserves booking practices.Our results indicate that reserves booked increases more than linearly as a function of drilling. These results are confirmed by conversations with industry experts and support the conclusion that players in the industry tend to be conservative, delaying reporting of reserves. This is contrasted with the "diminishing returns" concept where there is a large increase in knowledge (i.e. reserves booked) during the initial phase, and then beyond a point, the gain in knowledge is less than proportional to the gain in effort spent (i.e. drilling).In order to arrive at a compromise "best practice" for booking reserves, we recommend a linear relationship and propose that reserves booked from the field should be directly proportional to the number of successful development wells drilled. This will help in capturing the true Finding and Development (F&D) cost of different basins and their relative competitiveness.