Mexico's oil production has been declining for the last decade. Therefore, the country has established strategies to increase oil production including the acquisition of new technology to produce unconventional reservoirs as well as the implementation of new regulations to enhance recovery rates from mature fields and develop the shallow-water and deepwater areas. This paper presents a detailed analysis of Mexico's new hydrocarbons legislation with special focus on the contracting and bidding processes. This research also considers available data to identify the main technical challenges associated with the contractual areas which ultimately may be crucial in increasing oil production. Prospective production from main Mexican reservoirs was evaluated using a probabilistic method based on decline curve analysis (DCA) to forecast Mexico's oil production and its effect on North America oil production outlook. The results of the technical evaluation of the contractual areas along with the analysis of the new policies indicate optimistic scenarios for the development of projects and a potential increase in oil production. These projects will foster offset decline of oil production by attracting experienced companies capable of facing current technical challenges and increasing upstream investment. Furthermore, areas of opportunity in the new regulations were identified to make the project conditions more attractive for companies and government. This study is built upon the exhaustive analysis of the new legislation and characteristics of the contractual areas in the context of the current internal and external factors to forecast Mexico's oil production scenario.

Acquisitions & Divestitures ("A&D") professionals routinely adjust the valuation parameters, on the basis of asset type being evaluated, to determine an acquisition price that is conservative yet competitive for use in a bid. A study of over seventy three A&D transactions over a two year period enabled us (the author’s team) to compare the valuation parameters for unconventional asset acquisitions vis-à-vis those for conventional asset acquisitions. Transaction data indicates that valuation metrics, particularly on a production multiple basis, for the acquisition of unconventional assets are significantly higher vis-à-vis those for the acquisition of conventional assets. The use of higher valuation multiples implies that the A&D market expects an unconventional asset to have lower risks and/or better growth prospects in relation to a conventional asset. SPEE Monograph 3makesit clear that an unconventional asset – a term often used in A&D markets to describe a continuous hydrocarbon reservoir of low permeability which exists over a large geographic area and requires extensive stimulation to produce at commercial rates – does not always have fewer risks and/or more growth prospects. Therefore, the acquisition of an unconventional asset at overly aggressive valuation could potentially lead to underperformance and adverse financial consequences for the buyer. The high valuation multiple for Halcón Resources Corporation’s ("Halcón") acquisition of its Woodbine unconventional play in Texas, which so far has not met expectations, provides a glaring, well-documented example of underperformance with adverse financial consequences in recent history. We believe buyers should use high valuation multiples with confidence only for those unconventional asset transactions which involve"resource play reservoirs" as defined in SPEE Monograph 3. 1 Using a cash flow based analytical framework outlined in the paper, we argue it is highly likely that a resource play reservoir would offer lower risks and/or better growth prospectsvis-à-vis a conventional asset, all else being equal. Hence, in relation to the acquisition of a conventional asset, the valuation multiples for the acquisition of a resource play reservoir – a subset of unconventional asset deals – should indeed be higher. For the remainder of unconventional asset deals, the practice of valuation at high multiples could lead to perilous financial consequences. The paper concludes with our recommendations for due diligence and deal structuring with respect to an unconventional asset acquisition. We identify due diligence items which include the determination of whether or not an unconventional asset exhibits the technical characteristics of a resource play reservoir. Unfortunately, such determination requires extensive well data. Early in the exploration process, it may not be possible to determine if an unconventional asset has the technical characteristics of a resource play reservoir due to the lack of adequate well count and data. For such early stage unconventional asset acquisitions, we discuss certain deal structuring techniques which could potentially make bids more competitive and less risky.

This paper considers the role of hedging and speculation on future oil prices. In July 2008, oil prices topped over $140/bbl then tanked to below $50/bbl by December of the same year. Many including officials, suppliers and consumers blamed futures markets, especially the speculators, for the oil price volatility ( Buyuksahin 2012 ). Shenoy (2011) relates the increase of non-commercial traders and contract volumes to the price fluctuation. Further, Shenoy (2011) disregards the market fundamentals and claims they cannot justify the high prices. However, others find market fundamentals to be more important. U. S. Energy Information Administration (EIA) (2007) and Krugman (2013) cite activities that have caused oil prices to increase and state reasons that support market fundamentals. These factors include geopolitics, rapid world economic growth, decreasing production, little surplus oil production capacity and inelastic oil demand. In this paper we investigate whether we agree with these latter papers that the big price increase from 2007 to mid-2008 is better explained by market fundamentals. Financial theory shows us that for speculators and the futures market to raise current cash prices, they must induce shifts in demand or supply in the cash market. Such shifts can come from inventory changes in the cash market or from producers shifting their production profiles. Thus, if futures prices are bid up by speculators and high futures prices are causing commercials in the cash market to increase inventories or producers to reduce production, then speculators are contributing to the price increase. There are three links in the chain that we need to investigate to support the speculator story. First, speculator positions in the futures market must be reinforcing the futures price changes; they must be buying when prices are increasing and selling when prices are falling. Second, the futures price must be inducing players in the cash market to be shifting their positions in a pattern consistent with changing future prices. If future prices are higher, buyers of crude should be buying and putting crude into inventories and sellers of crude should be withholding production and increasing spare capacity. If future prices are lower, crude buyers should reduce purchases now and run down inventories, and sellers should increase production and lower their surplus capacity. Finally, the futures price and the spot price movements need to be lined up. Thus, we expect higher futures prices to coincide with rising spot prices and lower futures prices to coincide with lower spot prices. To support the market fundamental hypothesis, we will explain the fundamentals of how hedging and speculation affect oil prices. Such fundamentals will clarify many misconceptions and show when hedging and speculation reduce price volatility and make the market more efficient and when they do not. Finally, we will consider oil price volatility since 2004 with particular emphasis on the oil price spike in 2008, which was followed by a significant collapse. We will consider if the three links in the chain above hold and support the hypothesis that speculators were responsible for the big price run-up and collapse as well as other less notable price movements since 2004.

From 2009, when the first offshore bidding round took place in Uruguay, and in particular from the second bidding round that constituted a enormous step in the exploratory history of Uruguay, our country faces a new and nontraditional hydrocarbons upstream activity. Government take, including the National Oil Company association in the case of a discovery, is already fixed under the Production Sharing Contracts in force and do not vary much with the field size. Therefore, a possible strategy to maximize the local revenues (income from Uruguayan services, products and human resources), which constitutes a key part for a sound distribution of petroleum revenues within the country, would be to increase the local content in the supply chain. Taking into consideration analogous geological basins, and the geological and technical probability of success for offshore Uruguay as a frontier basin, the field size and hydrocarbon potential was evaluated from a stochastic point of view. The cash flow analysis of a hypothetic oil development was carried out, incorporating the actual economic variables of the contracts in force offshore Uruguay, as well as the current fiscal regime. The standard project parameters, investments yardsticks and the government and contractor takes were calculated with the aim to obtain the Uruguayan rent and the relative impact of the local content. This work constitutes the first approach to the analysis of expenditures and investment during the current stage of exploration, and the eventual phases of appraisal, development and production offshore Uruguay. The technical and economic evaluation applied to a portfolio of offshore prospects models the level of expenditures and investment from exploration to production. The assessment of the potential impact of the activity on macroeconomic variables is carried out considering the local services and products that would be necessary for each stage, in order to identify the areas where increasing local content will provide the larger impact in the country economy.

This paper examines the wide variety of international agreements that are currently used by host governments when granting rights to explore for, develop, produce and market hydrocarbons. The variation in fiscal terms found in these agreements covers a broad spectrum. In addition, their structures are often very complex making comparison of alternative project opportunities difficult. The key differences in the agreements and approaches that are commonly used to compare different fiscal regimes are discussed. Case examples are used to illustrate the techniques used to model and perform economic evaluations of specific agreement types and terms. Commonly used definitions and accepted practice for the determination and classification of hydrocarbon volumes are presented. Host and home government regulations that govern and establish the criteria for external reporting of reserves and related financial information are also discussed in contrast with internal reporting needs for technical and business planning purposes.

Abstract Gas fields were developed by the Soviets in Afghanistan in the 1960s and 1970s. Gas infrastructure has deteriorated since their departure. There are attractive business opportunities for developing the natural gas sector. This requires simultaneous development of the upstream fields and facilities, downstream markets, transmission and distribution infrastructure, and the legal/regulatory framework governing gas activity. Introduction Media attention on Afghanistan focuses on conflict. But commentators have suggested the best way to bring stability to the region is to create a successful economy. There are proven reserves of natural gas in the north of the country, a region that is relatively stable. A fertilizer plant and a small number of residential and commercial customers are currently using gas. Investment to develop the reserves and markets for the gas will provide jobs that begin to stimulate the local economy. The gas itself can be used to generate power that is desperately short in Afghanistan, provide heating for residences, for commercial uses such as bakeries, and potentially as a vehicle fuel (either as compressed natural gas, or as feedstock for a gas-to-liquids plant). This paper discusses the history of gas production in Afghanistan and current activity that is under way to develop the natural gas sector. History and Present Circumstances The USGS recently estimated the mean undiscovered hydrocarbon resources in the Amu Darya and Afghan-Tajik basins in northern Afghanistan to be in the range of 100 to 1000 billion m 3 (3.5 to 35 TCF) of gas, 0.4 to 3.6 billion barrels of oil and 0.1 to 1.3 million barrels of natural gas liquids. (1) During the 1960s and 1970s the Soviet Union discovered and developed gas reserves near the town of Sheberghan in northern Afghanistan, see Figure 1. The gas production rate in the late 1970s was about 10 million m 3 per day. The Soviets built gas conditioning plants at two of the fields for acid gas removal and dehydration (see Figure 2), and partially completed a compressor plant. The majority of the gas was exported to the north through what is now Uzbekistan. They also built a urea fertilizer plant near Mazar-e-Sharif, about 100 km to the east, with a capacity of 105,000 metric tons per year. Figure 3 shows a map of the discovered fields. Three fields have been developed: Jarquduq, Yatimtaq and Khvajeh Gogerdag. There was a blow out at the Yatimtaq field in 1962 that burned for about three years. Estimates of the resulting gas losses range from 7 to 20 billion m 3 . Cumulative production from these fields through 2002 was about 63 billion m 3 . The remaining discovered fields have not been produced. The Soviets drilled exploration wells, but these were not suitable for production. As the Soviets departed the country in 1989, they took most of their records, killed and shut in all of the producing wells and temporarily abandoned the fields. Very little original data remained in the country following the withdrawal. However, subsequent researchers have uncovered sufficient primary and secondary data to establish the gas reserves. The data was gathered with obsolete technology, and much of it is anecdotal in the form of worker's notebooks and other unofficial sources. There are estimated remaining reserves of about 34 billion m 3 in the developed fields and 43 billion m 3 in the undeveloped fields. Today the gas production rate is about 500 thousand m 3 per day. Figure 4 shows one of the operational Jarquduk wells. The gas plant facilities are used only for a small amount of liquid knock-out. The fields are operated by Afghan Gas, which employs about 1080 people. The fertilizer plant is the main gas consumer. It employs about 2550 people, but operates at only 40% of capacity due to a lack of gas supply and a shortage of spare parts. It receives sweet gas through an underground transmission pipeline. There are widely varying reports about the amount of gas leakage from this pipeline. The official price of gas delivered to the plant is $25 per thousand m 3 (about $0.70/MMBTU).

Abstract Ring fence provisions are often ignored or greatly simplified when determining the value of a portfolio because of the complex modeling required.After reviewing the theoretical effects that ring fencing can have on both the value and expected value of portfolios, tests were run using actual fiscal terms and ring fence provisions in nine countries to determine the significance of the ring fence effects and whether or not the effects on portfolio value could be predicted prior to the complex modeling process by examination of the fiscal terms.While significance is a judgment that must be made by each analyst, the results otherwise indicate that prediction of the significance of proper ring fencing is virtually impossible in most situations because of the complex interactions among various fiscal components.The results seem to suggest, though, that proper ring fencing in fiscal systems with no sliding scales in any of their tax or production sharing contract terms will almost always enhance the value of the portfolio. Introduction Ring fence provisions are either directly or indirectly specified in every petroleum contract or tax system in the world.These provisions specify the portfolio level (e.g. field, block, license) at which each fiscal component (e.g. royalty, tax, cost oil, profit oil) is to be calculated. For a variety of reasons, these ring fence provisions are sometimes ignored or overly simplified when determining the value of a portfolio. This paper reviews common ring fence provisions and explains the theory of how these provisions may affect the value of a portfolio.It then reviews how ring fence provisions may complicate a very commonly used uncertainty analysis tool - expected value.Finally, a series of tests were run to determine if ring fencing significantly affects the value of a portfolio, and because of the complexity of modeling ring fence provisions, whether or not the direction and magnitude of these effects can be predicted in advance. Definition of Ring Fence Provisions In every country in the world, regardless of the type of fiscal system in place, there is either an implicitly or explicitly defined hierarchy of fiscal calculations. These calculations must be performed in a certain order to ultimately determine the after-tax cash flow for a country portfolio of upstream oil and gas projects.There are two sets of variables at play in determining these calculations and their sequencing: the type of fiscal vehicle, such as income tax, royalty, cost recovery, or profit share, and the political or contractual entities under governance of the fiscal authorities, such as field, province, license or country. For each political entity in the same country, there may be a different fiscal vehicle defining how that level of the government shares in the overall "take." For example, a province may claim a royalty, while the country as a whole receives income tax. Below we discuss two examples in greater detail to illustrate the impact on NPV.

Abstract Brazil has been developeding strong offshore E&P oil activities. The objective of this paper is to propose alternative policies for Brazil to boost onshore activities, reducing its exposure to the economic cycles of the petroleum business. In particular, new contract mechanisms should allow for a more attractive splitting of risks between the country and investors; inducing favorably the latter's investment decisions. Introduction Since 1999 the National Petroleum Agency - ANP, the federal organ that has been attributed the right to grant permissions for E&P oil activities in the Brazil, has held four annual bidding rounds. In all, 157 areas were offered: 40 land based and 117 at sea. From those, 87 areas were granted for exploration: 27 on land and 60 at sea. That is, sea based areas correspond to70% of the total. 1 Therefore, the tendency to concentrate efforts offshore prevails. One should point out that this tendency has been dominant since the middle of the seventies, which resulted in Brazil having found most of its proven oil and gas reserves at sea. Fig. 1 demonstrates the evolution of the Brazilian reserves in the last ten years. The Campos basin was transformed into one of the most prolific off shore areas in the world. On Table 1 , we can see the share of the Campos Basin in the national total oil and gas production. Brazil's, enormous onshore sedimentary areas have been little explored and its development potential has stagnated. On Tables 2 and 3 , one can respectively observe the recent evolution of Brazil's smaller oil and gas production onshore as well as some projections up to 2005, given us the current business condition. Investments so far in the onshore basins are relatively small compared to the offshore segment. For example, in 2002, the national oil company, Petrobras, which holds 98% of the total proven oil and gas reserves in the country, invested almost US$ 3.4 billion in production development, of which US$ 2.9 billion were destined to the offshore fields. 2 With the opening up of the Brazilian petroleum sector in 1997, after the approval of the New Petroleum Law - NLP 3 , other large oil companies have been interested in developing E&P activities in the country. Many in partnership with Petrobras, and they have also primarily focused on offshore.These activities, however, being more complex and demanding larger investments are accessible mostly to the larger oil companies, with capital available and higher propensity for risk. Brazil's crude oil production is growing fast. The country is prepared to attain the self-sufficiency by 2005. As shown in Fig. 2 , the share of domestic production in the national crude oil consumption increased from 53% in1992 to 90% in 2002. The nation is certainly less vulnerable regarding its dependence on crude imports. 4 However, as Brazil acquired world recognition as an important area for high-tech and more expensive deepwater offshore oil, the country still finds itself highly exposed to the economic cycles of the global petroleum business. Most of new entrants are global players with important stakes elsewhere. Theymay be tempted to give up or reduce substantially the commitments with the country unless they can improve the economic conditions of their projects in Brazil. Since nations are fighting fiercely to attract foreign investments, particularly for developing more complex offshore activities, Brazil may have its bargain power damaged by a more competitive environment in its major upstream segment. Brazil must therefore find ways to diversify its upstream industry, trying to increase the attractiveness of its large onshore sedimentary basins. The country must induce the entrance of a greater number of small-and-medium size companies. Brazil's onshore areas can become an important niche of market for those smaller investors.

This paper was prepared for presentation at the 1999 SPE Hydrocarbon Economics and Evaluation Symposium held in Dallas, Texas, 20-23 March 1999.

Marlan W. Downey* Abstract Political risk assessment provides a prediction of the likelihood that future foreign government actions will deteriorate the return on a planned foreign investment. Such political risk predictions are commonly provided with great assurance by political experts. Political risk assessments are frequently quantified to two or three significant figures, so that comparisons can be made between various countries, at various times in the future. It is my contention that most of such quantifications and predictions are nonsense; that the political future is not being accurately predicted. It is useful to describe some general axioms on predicting the future: Future events can be predicted in a rigorous manner only if they represent expected outcomes of physical laws; Future events can be predicted with some statistical confidence if they represent a modest extrapolation of consistent history into the future; The farther into the future one predicts, the less reliable history-based predictions should be: Predictions become less certain as more parameters influence the event; Predictions must be less certain as more precision Is required; and Predictions of singular future complex political events are merely guesses, no matter how they may be swaddled in statistical mumbo-jumbo. For proper analysis of political risk it is important to create multiple scenarios of the future, to be well acquainted with foreign politics, and to understand the economic fundamentals of the country where you are considering investments. Such approaches allow management to look for possible flexibilities in investments, to consider insurance, hedging, and other risk abatement techniques against some of the most likely negative political/economic outcomes. The proper investor question is … "what can I do to mitigate possible future country risk?" … not, "what is the proper discount factor to allow for future country risk?" Wise investors need to take positive actions early in the investment cycle so that they may alter, rather than hope to measure, political risk in foreign investments. Introduction Risk assessments are an everyday part of project management. Understanding risks, mitigating risk, discounting for risk are attempts to determine the uncertainty of the outcome of projects. Political risk assessment is an analysis of a particular kind of risk; P. 7

Kurt Korte Abstract Over the past decade, the energy "paper" market has grown into one of the largest traded markets in the world providing hedging instruments for the producer as well as the enduser of energy products. Because banks, stockholders, and other financial providers rely on a borrower's ability to generate cash flow to repay their investment, borrowers are increasingly turning to the derivatives markets to provide security against one of the most volatile markets in he world. The existence of this market has enhanced the ability of financial institutions to lend with confidence and appropriate aggressiveness to the oil and gas industry. Introduction Oil and gas reserves are a depleting asset, and every day that a well is producing, the producer's assets are shrinking. Thus oil and gas producers need to acquire properties to continue to survive and grow. Most companies need to borrow money to grow, but given the price volatility related to the oil and gas industry, it can be costly or not readily available. The use of energy derivative products can increase the amount of available cash and can reduce the cost of borrowing it, making the acquisition of properties all the more possible. By giving a broad education on the building blocks of energy derivative (hedging) products, I will demonstrate that financial institutions will and do show more comfort in lending to or investing in companies who have removed at least a portion of the energy price volatility. P. 267

SPE Member Summary This paper presents a review of managing oil and gas product price risk with the basic types of derivative products available to producers. Introducing the futures markets, basic types of hedges and factors affecting prices will be covered. Several case histories will be discussed in detail from the initial decision making process to actual performance to date. Introduction Risk management for product prices using the futures and commodities market is not a new concept. It has been available to the agricultural markets since before the Civil War and since 1933 for the precious metals markets. Crude oil was the first energy contract to be commoditized in 1983. The natural gas futures contract opened for trading on April 3, 1990. The market that transacts all energy futures is the New York Mercantile Exchange, conveniently known as the "NYMEX." Crude oil is traded up to 34 months into the future, in 1,000 barrel (bbl) increments, and listed in $/bbl Natural gas is traded up to 18 months into the future, in 10,000 MMBtu increments, and listed in $/MMBtu. Both oil and gas are also traded in the futures options market on the NYMEX which is subordinate to the futures market. The term "Derivatives," which means derived from the futures and options markets, is the common word used today to describe hedging and risk management. This paper will cover only the three basic derivative products: swaps, floors, and collars. Risk management does not mean eliminating price risk but rather transferring that risk to a determined price. The current industry view on oil and gas prices for the long term future is $18 to $20 per barrel and $1.90 to $2.00 per MMBtu with modest annual escalations. Because of the nature of oil and gas production and consumption, producers should plan on short-term price volatility always being present. The ability to protect against a fall in prices and be able to take some advantage of price increases, which hedging in the derivatives market provides, is invaluable to planning, budgeting, and financing. The use of derivatives for oil and gas interest will be necessary in order to remain competitive and profitable in the industry. Background To arrive at a description of the derivatives market one must understand the basics of the futures and options markets. A futures contract is the buying of a specified volume at the current quoted price for a specific month in the future. Once a futures contract is bought, it can be sold back to the market or held until it expires. Upon selling or expiration of the contract the buyer will receive the quoted price which may be more or less than the original purchase price. An options contract is the right to buy or sell a futures contract at a specified price and time. The specified price is often called a strike price. P. 275

SPE Member Abstract This paper examines the dynamic international political economic environment In which petroleum exploration and production companies must operate when considering investments in the economically transitional nations of the former Soviet Union or developing nations In this period of critical global changes low oil prices is only one factor with which petroleum companies must be concerned in their investment decisions. Other factors include the transition from a bipolar world to a multi polar world of free trade zones. The general malaise of the international economy. public and political recognition That nations and industries can no longer practice environmental "beggar-thy-neighbor" policies. and the rejection of aggregate national economic growth policies for sustainable economic development policies in both the developed and developing world. This paper focuses on actions which investing petroleum exploration and production companies can take in order to gain a leadership role in the sustainable petroleum economic development business, to work with host countries' regulations, and to develop a cooperative environment with host countries so that both the investing company and the host country can progress, not just survive. II. Introduction When an international petroleum exploration and production company is making the decision of whether to invest in an economically transitional nation of the former Soviet Union or a developing nation, the investing company must consider the larger international economical and political environment in which it has to operate whIle maintaining its long term investment duration in the host country. Oil prices, costs of production. and the level of sophistication of extraction methods can no longer be the only considerations. The global political economy on the brink of the Twenty-First Century has been and is expected to continue to be in a general malady of high unemployment. low interest rates, and volatile regional and ethnic politics threatening national economies. Increasing recognition of indigenous peoples' property rights are challenging investing petroleum and mining companies' tenure in host nations. The collapse of the Soviet Union and the Warsaw Pact has suddenly thrust the global political economic structure from a bipolar to a multi polar one Although the transition to a multIpolar world is yet incomplete, it is most likely to be a world of emerging free trade zones The European Council is fully operational The North American Free Trade Agreement (NAFTA) passed last year has created a tree trade zone of Canada, the United States, and Mexico. P. 33

Abstract In comparison with the pricing mechanisms that prevailed for crude oil and natural gas from the 1940s through the 1960s, the current price environment is exceedingly volatile. In response to this volatility, financial products called derivatives have been developed in the last decade. Of these, the commodity price swap is finding acceptance as a tool to manage price risk. This paper is an introduction to commodity price swaps for those individuals whose responsibilities include managing a portfolio of oil and gas assets, but who have not had direct experience with swaps. In addition to a description of the basic fixed-for-floating swap and its variations, the historical evolution of swaps is outlined. The significant contract terms and the special problems associated with swaps are also summarized. Selected applications of commodity price swaps which may be useful in managing a portfolio of petroleum assets are described. These applications include: Locking-in Project Economics Swaptions Prepaid swaps Synthetic oil (or gas) fields BTU swaps Swaps have experienced a rapid growth rate since their introduction in the interest rate and currency exchange markets in the early 1980s. Commodity swaps offer promise as a new tool to those firms which hold a portfolio of petroleum resources, developed or undeveloped. Note that this paper is not intended as an authoritative reference with respect to the legal, tax and accounting issues associated with commodity swaps. Given the rapidly changing legal and regulatory context of swaps, it is advised that readers seek current opinions from their appropriate legal and accounting advisers. Introduction In the 1980s, prices for crude oil and natural gas became driven by the spot markets. Prior to this, crude oil prices had been controlled to varying degrees by the international oil companies, OPEC, and the Texas Railroad Commission. Similarly, domestic natural gas prices had been controlled by the Federal Power Commission and later, the Federal Energy Regulatory Commission (FERC). This resulted in relatively stable and, perhaps more importantly, predictable oil and gas prices. Except for a six percent decline in prices from 1958 through 1960, the price of West Texas Intermediate (WTI) slowly rose from 1940 through 1981. (See figure 1.) This market control was especially evident in the period from 1960 through 1965: the posted price for WTI remained constant at $2.65 per barrel. OPEC's control of the oil market in the early 1980s loosened as the spot markets for crude oil grew in importance. P. 165^

INTRODUCTION AND BACKGROUND Apart from some exceptions, everywhere the State is the owner of the natural resources in its territory. Therefore, the exploration for oil and gas, being natural resources, entails the execution of agreements between the Oil Companies and the local governments. Such agreements are governed by a proper contract setting out different items: the area, the duration, the work and/or expenditure commitments, the possible taxation and/or the sharing of production. Whilst in some countries the contracts are governed by petroleum laws and actual negotiations do not take place, in others, many issues are negotiable from time to time. The model agreement is somewhat linked to the petroleum history and to the evolution of the producing countries' attitude vis-a-vis the oil activity in their territory. At the beginning, the contracts were concession agreements, characterized by a long duration, very large areas (which, at times, covered the entire country) and lack of precise expenditure commitments by the Oil Companies. Production royalties and income taxes were paid to the host governments. In the 1960s, the concession agreements were marked by stricter provisions and a general increase in the taxation level. Afterwards, the producing countries' state-owned oil companies were associated with the Oil Companies, with the consequent sharing of both production and profits. In the 1970s, the production sharing agreements were devised, thereby conceptually superseding the previous models. Thanks to this type of contract, the Oil Companies are sheltered from nationalizations since they do not own assets, but they acquire legal rights by virtue of the activity they carry out. Today, the production sharing agreement is very popular and in many countries it is the only possible contract, whereas in others, the concession agreements are still in use, even though in different forms. MAIN ELEMENTS OF THE PRODUCTION SHARING AGREEMENT The expenditures and the risks related to exploration are always fully borne by the Oil Company which may recover such costs only from the production obtained from discoveries. Furthermore, the agreement provides for a work and/or expenditure commitment to be undertaken in a limited number of years (2 or 3 years), with the possibility of extending such periods of time. When the production phase is reached, the agreement's basic elements, i.e. the Cost Recovery Oil and the Profit Oil, generate an economic return for the Oil Company. P. 229^

Abstract This paper examines how the desires of the Nigerian government as expressed in the Petroleum Development policies have acted as incentives or disincentives policies have acted as incentives or disincentives to further investment in oil field development in the face of uncertain economic environmental conditions and reserve sizes. An economic analysis package was used in evaluating past and present fiscal and contractual policies. past and present fiscal and contractual policies. The Net Present Values (NPV) of large, medium and small hypothetic fields were computed for the principal environments of oil exploitation (onshore and principal environments of oil exploitation (onshore and offshore) in the Niger Delta. This was done for various policy combinations to determine the sensitivity of the policy based profitability to oil price, production cost, delay in field development and price, production cost, delay in field development and production, operating companies share of profit production, operating companies share of profit and discount rates. The results were analysed and the attractiveness of policy packages to new investors were compared and ranked. It concludes that Government policies have evolved to diminish the profitability of investors from oil exploitation. The present policies would require incentives to attract new investors unless production costs are reduced, oil prices rise and medium to large fields are the most likely to be discovered. New entrants that have to "carry", government operate under the worst policies are not likely to be attracted under existing situations. Introduction The decision by an oil company to invest in exploration or production is generally influenced by a number of factors: the satisfaction of a strategic corporate need and the economic outcome of such a decision. Where economics is a crucial factor, a number of parameters such as cost of production, the anticipated price of the produced oil, and the political environment under which these economic political environment under which these economic factors operate, have a major role to play in the decision-making process. The nature of government and the prevailing policies of such a government therefore, have far-reaching implications on petroleum investment. petroleum investment. In Nigeria, the petroleum development policies have undergone a number of changes. Over the years, policy postures have changed from the initial policy postures have changed from the initial situation where government was merely collecting taxes and royalties, and regulating oil company activities to the present position of active participant in the oil industry. This evolution has introduced some complexities in the economic evaluation of petroleum ventures. Government petroleum policies are made up of: Fiscal policies; Various petroleum arrangements; and Regulations. The fiscal system is formulated and implemented through legislation. It is generally composed of two essential parts: Economics - which contains provisions regarding the factors that have direct bearing on project economics, such as tax, rent, and royalty as well as timing for exploration, field development and production. Other provisions include minimum investments to be made during some phases of oil operation. Operations - refer to those provisions which regulate the manner in which exploration and production activities are conducted. P. 139

Introduction The natural gas industry has quickly changed from one which was dominated by long term contracts between the producer and pipeline to one that is characterized by producer and pipeline to one that is characterized by contracts of much shorter duration. Part of the reasons for this change are economic, and part are due to the changing regulatory structure surrounding the industry. Over the last ten years the number of natural gas wells in the United States has steadily increased, from around 144,000 in 1977 to around 240,000 in 1987. See: Figure 1. While the number of natural gas wells has steadily increased the total amount of natural gas reserves in the United States has remained relatively constant. See: Figure 2. As a result, the reserves attributable to each natural gas well has declined from 989 MMcf per well in 1977 to around 588 MMcf per well in 1987. See: Figure 3. Demand for natural gas has declined from the early 1970's, from a peak of around 22 Tcf per year to a low of 16 Tcf in 1986. Demand has not declined from 1986 levels and has grown slowly to an estimated level of around 18 Tcf in 1988. Future demand for natural gas depends on many factors, including the price of competitive fuels (mainly crude oil) and environmental concerns of end users using other fuels (acid rain, nuclear safety). Around fourty-five percent of the demand for natural gas comes from the residential and commercial sectors, and the remaining fifty-five percent is attributable to industrial and utility usage. This is significant because a main use of the gas consumed by the residential and commercial sector is for heating purposes. Because such demand is seasonal, depending purposes. Because such demand is seasonal, depending on weather conditions, transportation or production "bottlenecks" can occur during periods of peak demand. Figure 4 sets out the share of the natural gas market held by each consuming sector. Several of the factors noted above have had a major influence on the current evolution of the natural gas industry. First, due to the decline in demand pipelines had excess capacity that was not being pipelines had excess capacity that was not being utilized efficiently. Secondly, even though there were numerous gas wells which were shut in, the end user of the gas was not experiencing a decline in price at the burner tip even though prices were price at the burner tip even though prices were falling in the field. This was because pipeline purchasers were generally tied to long term contracts purchasers were generally tied to long term contracts with inflexible pricing terms. Thirdly, the producer had problems marketing his gas at any price due to transportation impediments, and could not move their gas from the field to the end user. As a result of the pressure from producers, pipelines, and consumers of natural gas the Federal Energy Regulatory Commission (FERC) issued a series of orders which profoundly affects how natural gas is sold and marketed. THE CHANGING REGULATORY ENVIRONMENT The FERC is given the responsibility of regulating the natural gas markets under the authority granted in the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The FERC is an administrative agency composed of five Commissioners, only three of which can be from the same party. The President nominates the Commissioners, who are then approved by Congress. By the mid-1980's President Reagan had replaced all of the appointees of President Carter, and all of the new appointees were predisposed against traditional forms of regulation following the administration's free market policy. P. 87

Introduction With the downturn in the U.S. oil economy, petroleum engineering and service companies are increasingly looking overseas for work. Many of the exciting developments in the petroleum industry are taking place in the developing countries, requiring parties place in the developing countries, requiring parties to accept unique foreign risks. These risks can, in many cases, be covered by a small number of private sector political risk insurers and the Overseas Private Investment Corporation (" OPIC"), a U.S. Private Investment Corporation (" OPIC"), a U.S. Government agency, which offers political risk insurance and, to a limited extent, financing for American companies with exposures in the developing countries. This paper describes how those risks can be insured. Discussion The Overseas Private Investment Corporation (" OPIC") is a United States Government agency designed to promote the economic development of less-developed promote the economic development of less-developed nations by assisting United States citizens, corporations and their wholly-owned (95%) foreign subsidiaries in efforts to invest, or develop contractual relationships, in the third world. As a complement to the U.S. Agency for International Development, which finances projects on a government-to-government basis, OPIC's purpose is to facilitate the transfer of U.S. capital, technology and management skills by helping American companies establish a broad variety of projects in Latin America, Africa, the Middle East, the Indian Subcontinent, Asia and parts of Europe (Portugal, Greece, Yugoslavia, Ireland and Northern Ireland). Its political risk insurance and finance programs operate either independently of or in conjunction with the programs of the Export-Import Bank of the United States, the World Bank (including the International Finance Corporation), the regional development banks, foreign government supplier credit and political risk insurance agencies and private political risk insurers throughout the world. While political risk insurers throughout the world. While Congress views OPIC as a development agency, corporate America views OPIC as an insurance company and a source of non-recourse (or project) financing. Companies buy OPIC political risk insurance for a number of reasons. While obviously most take coverage in order to reduce risks and receive compensation for losses, others are equally interested in the insurance for non-financial reasons. Because of the agency's vast experience in resolving investment disputes, some corporate executives place great importance on the fact that OPIC clients can turn to a U.S. government agency to help them resolve major investment issues with host governments. OPIC's involvement brings with it not only the full weight of the U.S. Government but also a direct financial interest in the outcome of any dispute; hence OPIC's participation increases the likelihood that disputes will be settled amicably and in legal and financial framework rather than in a public political arena. In addition, small companies which are deeply involved in third world projects will find that their bankers and major suppliers feel more secure when those exposures are insured against country risk by an agency of the U.S. Government. OPIC offers three types of political risk insurance: Inconvertibility - insurance against the deterioration in exchange control laws, regulations and procedures (not including devaluation); Expropriation - insurance against nationalization, confiscation and creeping expropriation, including, in the case of contracts with host governments, material changes in those contracts unilaterally imposed by the host government; and P. 173

Abstract The ail market of the late 1980's and into the 1990's is likely to be characterized by price uncertainty and volatility. The oil futures and options markets have developed to meet the needs of the petroleum industry to find a supplementary vehicle to reduce some of the risk surrounding pricing. This paper provides an introduction to the use of crude oil futures and options hedging by oil and gas producers. Introduction The incredible price volatility from late 1985 to the present, has signalled a fundamental change in the oil industry. Volatile pricing has made is extremely difficult to evaluate the economic viability of projects, and longer term planning faces paralysis. This paper considers the following items: Oil prices will be volatile in the future Low probability of accurate forecasting High cost of being wrong Risk reduction grows in importance Applications of oil futures and options. OIL PRICES WILL CONTINUE TO BE VOLATILE With a surplus of world oil production capacity, and more than half of current production outside the control of OPEC, we would have to be skeptical as to the ability of the Cartel to effectively set a price regime which would return pricing to the stability seen in the pre-OPEC era. Related to these fundamental supply characteristics, the growth of the spot, futures ana options markets makes supply demand imbalances rapidly known to a wide community of interests. Some argue the degree to which these markets create volatility of their own. Rather than enter that debate, we simply note that oil prices have become extremely volatile and are likely to continue to show substantial volatility in the future. LOW PROBABILITY OF ACCURATE FORECASTING Oil price forecasting continues to attract the considered efforts of many talented professionals, and oil price forecasts are still required to properly plan, manage, and evaluate projects but the historical record says clearly that we should have modest expectations about the accuracy of projections. Previous forecasts have been wrong, not by 5 or 10 percent, but even completely wrong in terms of direction. And those forecasts that turned out to be correct, were not credible at the time they were made. The solution is not to look for a better crystal ball, or embrace the latest Guru. (Remember even a broken clock is right twice a day.) The best course of action, it seem to us, is to recognize the inherent difficulty of nailing down a price forecast, and asking how do we most effectively operate in an environment where prices are apt to be volatile and not easily forecastable? P. 181^

Abstract With the introduction of netback deals negotiated in August 1985, the Saudis abdicated their role as the swing supplier to world oil markets. Their action ended 25 years in which first the international majors and then OPEC had held the line (officially) on crude prices at the expense of downstream margins. In 1986, oil price instability hit new highs, as sellers fought for market share in the absence of a "gatekeeper" on production and a marker crude reference price. Tranquility is not likely to be restored soon. Introduction In the early 1970s, oil belonged to the realm of the Seven Sisters—the international majors who produced most of the oil in the world outside communist areas (WOCA). Much of the oil flowed to end users through company-owned transport, refining, and marketing facilities. Company-controlled crude surplus to the major's requirements was supplied under long-term contracts to third-party (independent) refiners, particularly in Japan. The small amount of spot market (cargo-by-cargo) trading that did occur was mainly to correct short-term imbalances in refinery output of individual products. (Figure 1.) The Managed World Efforts to increase the volume of crude and product sales did create periods of price weakness. But in general, the majors acted as "gate- keepers" on production and balanced demand across different regions and market sectors. Their common interest in tuning crude supply to the requirements of the markets they served transcended national boundaries. They not only controlled much of the world's oil production through joint companies in Saudi Arabia, Iran, Iraq and elsewhere, the majors could draw from a constant flow of information needed to program supply from various sources. (Figure 2.) The companies' task was also facilitated by the growth in consumption as oil entered new markets and became the fuel of choice. For more than two decades (1950 to 1972), WOCA oil demand had been growing at a rapid, and fairly predictable, 7 percent per year. Consequently, integrated companies were concerned not so much to capture existing sales from a competitor as to ensure their own share of the growth. (Figure 3.) The result was that they managed to avoid destructive price competition. Nevertheless, it was during a period of competitive price weakness that OPEC was formed in September 1960, following a second cut in the posted price of Middle East crude to meet competition from other supplies. Concerned that their relationship with Middle East countries would deteriorate if further cuts were made, the majors made posted prices sacrosanct from then on. If downstream margins were squeezed by competitive pressures, the integrated companies simply maintained their postings and financed their operations out of profits from production. Clearly, posted prices create too strong an impression of stability during the 1960s and early 1970s, as shown in Table 1. Nevertheless, in the early years most of the oil which moved in international trade did so under long-term contracts at prices close to postings. It was not until the mid 1960s that the pressure of declining open market (spot) prices pushed contract prices below postings. From then on, posted prices were used solely to calculate oil company royalty and tax obligations. There was fairly uniform pricing for interaffiliate transactions. But third-party (contract and spot) prices were negotiated separately for individual customers, thereby differentiating among buyers and markets. This differentiation enabled the majors to balance crude supply and demand outside their own systems. P. 77^