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Summary This paper shows the applicability and the value of real options analysis (ROA) in valuing a marginal undeveloped discovery in the UK Continental Shelf (UKCS) under multiple project uncertainties, namely geology, costs, and oil prices. Marginal fields can prove uneconomic when developed under prevailing circumstances such as technical (reservoir size, infrastructure distance and remoteness, crudeoil type) or commercial issues (oil prices, high cost of development, lack of third-party-access arrangements), among others. As such, using traditional discounted-cash-flow (DCF) methodologies such as the net present value (NPV) might not adequately value the embedded options that these uncertainties create, leading to a rejection of the investment decision. Hence, we assess if the valuation differs if valued by the traditional DCF approach compared with ROA. We develop a valuation model for the traditional DCF and real options and specifically model the flexibility in the options to delay, abandon, or expand the field anytime during the relinquishment requirement period considering these multiple uncertainties. The binomial lattice and later the Black and Scholes models are used to model the options because of the flexibility they provide in incorporating early exercise. The results indicate that the DCF values lag those of the option values for the deferral and expansion options. In contrast, the abandonment option exhibited only a marginal change with respect to the DCF value. A significant implication of this finding is that management decision making will be better off considering these embedded options in their field-development and capital-investment choices. Introduction Many businesses seek to maximize shareholder value in a world of limited resources and competing strategic interest. Hence, the valuation procedure used to make investment decisions becomes important. In the petroleum industry, these valuations form the basis for the acquisition of leases through the bids and auctions used by governments to "establish presale reservation prices and to study the effect of policy changes on revenues it expects to receive from lease sales" (Smith 2003). As such, the valuation method used plays a fundamental role in determining the accuracy of these bids and auctions amid many prevalent uncertainties and unknowns, such as oil prices.
Abstract This paper performs uncertainty quantification (UQ) to capture the risk – both from investor and government perspective – to which an integrated petroleum development project is exposed to. The current fiscal system will be compared against the proposed PIFB 2018. Following the field development concept, the comparative economics are developed using Discounted Cash Flow (DCF) in recognition of the extant fiscal provisions. The DCF is expressed in nominal terms with sensitivity and stochastic modelling. The integrated development concept incorporates a 12kbpd refinery and a 150mmscfd gas plant on a 250mmboe onshore marginal field. The results indicate that the Petroleum Industry Fiscal Bill (PIFB 2018) delivers nearly twice in expected investor value than the current Petroleum Profit Tax/Marginal Field Regulations (PPT/MFR) on the integrated project. Furthermore, government take (GT%) shrinks from 45% under the PPT/MFR to 28% under the proposed regime. Stochastic analysis shows that investors are less exposed to failure under PIFB fiscal terms and instruments than the PPT/MFR. There is a higher likelihood (54%) of investor failure under the PPT than the 46% probability of a loss under the PIFB. The expected GT under PIFB is lower than that under PPT, however, there is significant likelihood (>65%) that neither system will deliver to government as much as the expected lifecycle Take. However, decoupling the value chain reveals varying risk reward profiles for the different segments with implications for policy formulation. A key insight drawn from the study is for policy makers to encourage the development of integrated projects to deliver a "portfolio" government take. This will smoothen out volatilities in tax receipts given that in this integrated development, government inflows from the different value chain components have different timings, levels and uncertainty.
Abstract Oil price forecasting has been shown to be challenging if not impossible for the long-term. However, the oil price has a major impact on Exploration and Production projects. Historical Project Realized Oil Price (PROP) can be calculated for example projects by summing up the total project revenue using the actual oil prices and dividing through the total amount of oil produced. For different starting dates of example projects, the PROP changes. Determining the PROP for different starting times, a Cumulative Distribution Function (CDF) can be derived. Adjusting this CDF for expected "half cycle breakeven costs" for the low limit and demand considerations for the high case leads to a PROP range that can be used for future project evaluation. Including PROP ranges into project evaluation allows for the selection of the most attractive development option, Value of Information analysis and project Probability of Economic Success (PES) calculation including oil price uncertainty. Furthermore, using PROP ranges rather than oil price scenarios enables a distinction between short-term budget planning and long-term project development. For budget planning, a scenario approach is suggested while for long-term planning PROP ranges should be used. Applying long-term planning on PROP ranges leads to less fluctuation in staff planning and small annual adjustments in PROP range forecasting. Also, using PROP ranges results in increasing PES project hurdles at low oil prices and lower PES hurdles at high oil prices. Hence, at low oil prices the risk averseness of the company is increased. Another effect of using PROP ranges is that at high oil prices robustness of projects to low oil prices is included in the assessment. To investigate the effect of PROP ranges on portfolio PES hurdles and project PES hurdles, a simplified linear-fit-model was developed. The results of the model showed that the project PES hurdles in a Value at Risk assessment can be determined applying the linear-fit-model to quantify the oil price dependency. The required individual project PES hurdles can be adjusted using the linear-fit-model to account for oil price uncertainty.
Abstract Performing robust economic valuation is critical to ensure success on oil development projects. In a dynamic market with ever changing variables, risks and uncertainties must be well analyzed and mitigated to prevent less than expected economic returns in mega-projects such as an offshore deep-water oil field development. This study aims to evaluate what are the most important factors that should be considered when assessing risks in a project economic valuation, using Brazil’s Production Sharing Contract (PSC) fiscal system as an example. A sensitivity analysis was performed in a standard offshore oil production project using the discounted cash flow method. First, a base scenario was calculated, and then, four key assumptions were chosen to be tested – oil prices, capital expenses (capex), operational expenses (opex) and recoverable reserves - and changes of + and - 20% in each, one at a time, were applied to the base scenario, and their impact on the internal rate of return and government take were measured. Findings indicate that, at least in the Brazilian PSC case, oil price is the most influential parameter in the project profitability, presenting an almost perfect positive correlation with the rate of return. Oil price is also the most difficult assumption to project and the one that is completely out of companies’ control, which poses them a significant challenge, to be able to keep its projects economical under volatile prices. Main investment decision gates happen years before first oil is produced, so the level of uncertainty on this parameter is very high. This study reinforces the concept that a good oil price forecast is paramount in projects valuation. Additionally, companies should always make investment decisions based on multiple oil price scenarios to determine the project’s financial risk.
Abstract Most reserves growth models have focused on mature fields in developed nations. Consequently, the direct application of such models to under-developed and developing nations with perceived maturing fields becomes challenging as the fundamental assumption in existing model formulations do not apply and are violated. The resultant resource management policies thus fail to meet the yearnings and aspirations of many under-developed and/or developing petroleum-dependent economies. This work bridges this gap using the formulation of a hybrid model that captures the peculiarity of under-developed and developing nations with attendant maturing field, towards their resources management. The modelling framework entails a hybrid of discovery-process, econometrics, and discounted cash flow approaches. However, for the purpose of this paper, policy application of the latter is the focus. Discounted Cash Flow (DCF) model framework adopted in this paper; is used to evaluate and investigate the impacts of volatility of oil price on oil and gas development economics using conventional, linear and logarithmic scales' fiscal policy schemes. Economic performance indicators such as Internal Rate of Return (IRR), Profitability Index (PI), and Take statistics are incorporated to evaluate investment performance. Sensitivity simulation approach is also incorporated to investigate its impact on decision variables. The overall aim is mitigating associated economic and technical risks in the highly risky and capital intensive oil and gas industry during low oil price regime. This paper recommends that resources utilization emphasis should be geared towards value addition by providing incentives that encourages more investment domestically, thereby opening up opportunities for its citizenry. Paradoxically, incentivizing and delaying gratification that encourages investments tend to yield approximate economic performance metrics as perceived regressive fiscal terms that would not encourage upstream E&P investments, ceteris paribus.
Abstract The Marcellus and Utica are among the most talked about natural gas plays in the country. In this paper their productivity and economics are examined, along with a production forecast. The type curves for natural gas and oil for different production areas within the Marcellus and Utica are compiled from well-level production data to gauge productivity differences between different parts of the plays. A drilling schedule is applied to the type curves to arrive at a production forecast for the various regions. Using the type curves and processing plant data, a natural gas liquids production forecast is provided as well. The breakeven natural gas prices and internal rates of return for the various production areas are calculated using a discounted cash flow model. These metrics are compared to other plays across the US to understand the competitiveness of the Marcellus and Utica, particularly in natural gas production growth, going forward. The Marcellus already boasts the best natural gas play economics in the country and will continue to be the cheapest source of natural gas production outside of natural gas volumes produced in association with oil-directed drilling. The Utica has great production potential, as can be seen in the impressive initial production rates already observed in certain windows of the Utica. However, the high drilling and completion costs and various operational problems need to be overcome if the play is to mature into the development phase. Both the Marcellus and the Utica will continue to see investment. The Marcellus will attract capital due to its already prolific economics, and the Utica will attract capital due to the high productivity potential that could be unlocked by marching up the learning curve.
Summary We discuss the two-factor oil-price model in valuation and analysis of flexible investment decisions. In particular, we will discuss the real options formulation of a typical oilfield-abandonment problem and will apply the least-squares Monte Carlo (LSM) simulation approach for calculation of project value. In this framework, the two-factor oil-price model will go a long way in the analysis of decisions and value creation. We also propose an implied method for estimation of parameters and state variables of the two-factor price process. The method is based on implied volatility of option on futures, the shape of the forward curve, and the implicit relationship between model parameters.
Abstract Allocating production volumes across a portfolio of producing assets is a complex optimization problem. Each producing asset possesses different technical attributes (e.g. crude type), facility constraints, and costs; In addition to these field-level specifications, there are corporate objectives and constraints (e.g. contract delivery requirements). While complex, such a problem can be specified and solved using conventional deterministic optimization methods. However, there is often uncertainty in many of the inputs, and in these cases the appropriate approach is neither obvious nor straightforward. One of the major uncertainties is the commodity price assumption(s). This paper tackles this problem in three major sections: (1) We specify an integrated stochastic optimization model that solves for the optimal production allocation for a portfolio of producing assets when there is uncertainty in commodity prices, (2) We then compare the solutions that result when different price models are used, and (3) We perform a value of information analysis to estimate the value of more accurate price models. Price modeling can affect decision-making, but it is surprising to find so little research that relates the price modeling assumptions (model type and the respective parameters) to the decisions that result from their use (capital investment, production optimization, etc.). Instead, we observe countless papers advocating for more and more complex price models, and an equally large body of work where models are estimated and compared for their accuracy. No one appears to have asked the basic question, "Do any of these models provide any incremental value for decision-making?" Here, we address this question by specifying an integrated stochastic optimization model that simulates decision-maker behavior. Using this model, we compare and contrast the various production allocation decisions that result from different price models. Simple price models are investigated and compared to several currently popular advanced price models with the goal of understanding the impact of price model assumptions (both the model type and its parameters) on decision-making. The results show that the optimum production allocation is a function of the price model assumptions. However, the differences between models are minor, and thus the value of choosing the "correct" price model, or similarly of estimating a more accurate model, is small. This work falls in the emerging research area of decision-oriented assessments of information utility/value. We believe it to be the first paper of its kind on this subject in the upstream literature.
Abstract Designing fiscal regimes that maximize government take is not a simple task, as countries are tasked to develop an overall fiscal mechanism that optimizes government take while encouraging capital investment and domestic production. Windfall Profits Taxes ("WPT") have been used to increase the percentage of government take in many countries. However, the terms "windfall profits tax" or "windfall tax" are loosely used and regularly confused with other forms of taxation. In many cases, taxes billed as windfall taxes are often forms of taxation specific to the exploration and production (E&P) sectors of the oil and gas industry. A discussion, therefore, is needed to clarify the differences between the forms of taxation under the heading, windfall tax. In a period of historically volatile prices, it is crucial for both producers and governments to have a detailed understanding of the triggers and affects of such taxes in order to best prepare for the application of these additional levies. This paper aims to detail the differences in windfall profits tax schemes currently in use around the world and compare their effects on the division of revenues related to E&P activities. It will be shown that the triggers attributed to a Windfall Profits Tax are rarely profits; instead these triggers are at best indirectly related to profits. Introduction Windfall Profit taxes have been used to increase government take in many countries. Designing fiscal regimes that maximize government take is not an easy task, let alone choosing a windfall tax mechanism or methodology that is beneficial for all parties, providing incentives, foreign investment, and maximizing the country's gain from production. The term windfall tax is loosely used and regularly confused with other forms of taxation. Therefore we want to start the discussion by clarifying the difference between two commonly used taxation methods as a proxy for a windfall profits tax: excise and income-based taxes. An excise tax is a taxation mechanism based on a commodity price. For example, a rate is applied over the sales production if oil prices exceed a certain baseline. Income-based taxes are those taxes related to income or profit related measures. As this paper will discuss, the calculation of these additional levies are generally driven by proxies signaling the possibility of windfall profits and not the windfall profit itself. Effects Economic theory suggests that the stakeholders in question, companies and governments, will react differently to differing implementations of windfall tax regimes. Though there are many variations of a windfall regime, as discussed above, significant differences in the economic effects of these taxes can be noted between excise-based and income-based windfall taxes. For the purposes of this discussion, those taxes triggered specifically by a comparatively high commodity price will be considered excise taxes while those related more directly to rapid increases in income will be considered income-based taxes. These income-based taxes are typically those whose rates and calculations are, ROR and R-factor driven. Excise An excise tax, by definition, is applied in the expectation of a windfall in revenue. Depending on the cost structure, this windfall revenue may not result in a windfall profit. In fact, such a tax may prove to have distortionary effects both on the energy market and petroleum project economics. An excise-based windfall tax has been shown to dissuade companies from exploring and producing in countries with such a tax in place, as was the case in the United States during the early 1980s.
Abstract In the exploitation of petroleum resources of a country, the interests of the host country and the investing oil company are not al- ways in alignment. Most significantly, economic rents expected from exploration and production tend to compete. The competing interests are best handled and reconciled through a win-win fiscal system that not only protects the interests of the host govern- ment, but also provides sufficient incentives to the investing oil company. Such a fiscal system enables E&P activities to proceed. The task, however, is not easy. A win-win upstream fiscal system is one that (1) encourages exploration, (2) promotes development of small as well as large pe- troleum reserves, (3) allows special incentives for difficult-to-explore or difficult-to-develop situations, and (4) enables equitable sharing of economic benefits between the host government and the investor. What constitutes equitable sharing is best judged from the relationship between the Government Take and the investor’s Rate of Return. A practical way to achieve a win-win a fiscal system is through economic modeling. Economic models constructed to represent various scenarios, each representing certain reserves, an exploration and development program, production profile, capex, oil price, etc., can be evaluated under the proposed contractual terms. The inefficiencies can then be removed by adjusting the fiscal terms. The process is one of trial-and error involving fiscal simula- tion of various exploration and development scenarios. The efficiency of Country A’s draft petroleum law, based on Royalty/Tax system, was evaluated through economic modeling. The evaluation, encompassing six scenarios, revealed that the pro- posed system, lacking the features of a win-win fiscal system, was economically inefficient. Instead, a Production Sharing structure with a graduated Profit Oil split, a cost recovery limit of 80%, and a sliding-scale income tax rate of 0-40% would yield the desired results.