This paper evaluates the economics of petroleum exploration and production (E&P) projects within the context of the expected economic value of a portfolio of blocks/fields owned and developed under the existing petroleum production sharing contracts (PSC), the jettisioned Inter Agency Team (IAT) memorandum on PIB 2008, and the Petroleum Industry Bill (PIB) 2012. The study incorporates important key variables in the determination of the expected or realized economic values from E&P projects including but not limited to location, technical cost & price, and field size. The model framework adopted for this paper is the Discounted Cash Flow (DCF) Model. The model framework is estimated by coding each segment of the DCF model equations in Microsoft Excel Spreadsheet to calculate deterministic economic and sytem performance measures, Government Take (GT), Discounted Government Take (DGT), and Front-end Loading Index (FLI). Two popular economic measures, the net present value (NPV) and internal rate of return (IRR), are derived and adopted to evaluate investment performance; and to account for uncertainties inherent in the data assumptions. A spreadsheet simulation tool is applied to quantify the impact of selected variables on relevant performance indicators using Monte Carlo simulation approach. Sensitivity analysis of decision variables and stochastic variables in the model is applied. The paper reports the P50 value of selected economic and system performance indicators. Simulation results show that for a viable deepwater project the unit technical cost (UTC) has to be within global average range of $27 and $35 per bbl; and contractor domiciling much of its cost at home. This enables the contractor to have a better IRR and helps to impact positively on local content. The result from this study shows that the PIB is less regressive than the earlier PSCs keeping in perspective our study assumptions.

Upstream petroleum industry remains one of the most prolific in terms of technology and risk capital transfer and rewards. Consequently, governments all over the world try to formulate fiscal regimes that could favourably attract investments to petroleum provinces in their jurisdiction. Fiscal systems that are progressive tend to find a common ground for both government and the contractor by optimizing efforts and benefits. Nigeria belongs to a region of low-risk hydrocarbon discovery relative to the world average. Therefore, the government designs fiscal regimes that would seemingly extract more economic rent from the development of its petroleum resources. This paper investigates the impact of some of the technical instruments in the Nigerian PSC on rewards from deepwater investments. Discounted economic models are developed for two petroleum sharing contracts in Nigeria- the 2005 PSC and the interagency team (IAT) redraft of the 2008 Petroleum Industry Bill (PIB)-with due consideration to the three Arps’ production decline profiles. Different tangible CAPEX depreciation methods are imposed on the models and profitability indicators are estimated. Monte Carlo simulation analysis is applied to resolve the stochastic nature of some model input variables. Simulation results show that maximum reward is observed when Unit of Production (UOP) depreciation method is applied in the redraft 2008 PIB; while straight line depreciation (SLD) gives better economic metrics for the 2005 PSC keeping all the terms of the contractual arrangements constant. These results could be applied in formulation of petroleum fiscal policies like the PIB by making cost depreciation a form of incentive. It is found that for a specific fiscal contract, cost depreciation method influences economic indices when used in project evaluation. Irrespective of the production decline, UOP depreciation gives earliest contractor-payout while the net present value is negatively impacted by accelerated extraction.

Petroleum Fiscal System (PFS) is a key determinant of investment decision in the exploration and production (E&P) of oil and gas. It describes the relationship between the host governments, the investors, and community stakeholders with respect to how costs are recovered and profits are shared equitably. A comparative economics of the performance of fiscal regimes becomes imperative as it affects stakeholders in making informed decisions on the oil and gas business investments worldwides. This paper evaluates the structure, conduct and performance of PFS in Gabon, Equatorial Guinea, Angola and Nigeria in the Gulf of Guinea (GOG). These countries hold about 90% of the GOG proved reserves. Economic analysis of the same E&P phases using hypothetical field and cost data under the different PFS are presented and discussed for comparative PFS performance evaluations. Comparison of the effects of production delay, front loaded government take and taxation shows that petroleum sharing contract fiscal terms and instruments in Gabon, Equatorial Guinea, Angola and Nigeria are relatively competitive. We found that as the risk in deepwater investment increases with water depth, return on investment rises in these GOG countries. Monte Carlo simulation process incorporated to account for risk and uncertainties reveal early discounted payout for investors in these GOG countries with significant degree of ceteris paribus.

Summary This paper presents a progressive royalty framework and investigates the effects of the various kinds of royalty schemes on oil- and gas-development economics. The conducts and performances of fixed, jumping, and/or sliding royalty schemes are evaluated. Further, the paper reviews the different sliding-scale specifications in fiscal systems and recommends the optimal boundary to ensure efficiency and effectiveness. The proposed royalty scheme recommended in the Inter Agency Team memorandum on the 2008 Petroleum Industry Bill (PIB) of Nigeria (PIB 2008), which was tied to terrain, geology, and value, forms the basis for the royalty design and modeling analysis evaluated in this paper. The logarithmic sliding-scale royalty scheme is generally perceived to perform better than other schemes (linear, jumping, or fixed scale), but our analysis shows that the effects of terrain and geology matter greatly. This implies that if the royalty scheme is tied to geology, then marginal field operators with marginal production rates would prefer the linearly sliding-scale mechanism to logarithmic scale. Flexibility to switch from one scheme to the other offers incremental fiscal-regime progressiveness in the quest for efficient, effective, equitable, and ethical energy-resource development. The paper recommends the use of the sliding-scale royalty scheme as a progressive bidding parameter and subsequent rent-extraction instrument. The uncertainty in oil prices and its plummeting trend—plausibly discouraging exploration and exploitation of the not-easy-to-find hydrocarbons—requires progressive royalty schemes to create equitable performance outcomes for all stakeholders in the emerging new petroleum era.

Summary The petroleum fiscal system (PFS) is a key determinant of investment decision in the exploration and production (E&P) of oil and gas. It describes the relationship among the host governments, the investors, and community stakeholders with respect to how costs are recovered and profits are shared equitably. A comparative economics of the performance of fiscal regimes becomes imperative because it affects stakeholders in making informed decisions on the oil-and-gas business investments worldwide. This paper evaluates the structure, conduct, and performance of production-sharing contracts in Angola, Equatorial Guinea, Gabon, and Nigeria in the Gulf of Guinea (GOG). These countries hold approximately 90% of the GOG proved reserves. Economic analysis of the same E&P phases with hypothetical field and cost data under different PFSs are presented and discussed for comparative PFS performance evaluations. Comparison of the effects of front-loaded government take, profit oil split, and taxation show that production-sharing contract fiscal terms and instruments in Angola, Equatorial Guinea, Gabon, and Nigeria are relatively competitive among these nations. We found that as the risk in deepwater investment increases with water depth, return on investment rises in Nigeria. Monte Carlo simulation process incorporated to account for risk and uncertainties reveals early discounted payout for investors in these GOG countries with significant degree, ceteris paribus.