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Summary In this work we evaluate the effects of the single-tier tax system (STS) at its current rate in comparison to the proposed dual-tier tax system (DTS) in the National Petroleum Fiscal Policy in Nigeria on project economic performance. We also expound on the arguments between two schools of thought (single tax and dual tax proponents) toward understanding the rationale underlying the divergent viewpoints. The methodological approach applies the discounted cash flow modeling framework to evaluate the performances of terrain-based projects using selected metrics, such as internal rate of return, discounted payout, net present value, and government take (GT) under the two tax systems. This approach calibrates the unit technical cost for typical deepwater projects in Nigeria and imposes the current and proposed fiscal terms. Varying cost treatment options and alternative allowables//incentives are investigated in the modeling framework using global best practices. We conclude that whichever tax system is adopted, it is possible to achieve equivalent economic metrics. However, the DTS presents a better, more flexible option over the STS because one of the split rates—especially the hydrocarbon resource tax—could serve as an instrument to incentivize investment, promote conservation, and expand the resource base through technology innovation more easily without denying the mineral owner an outright revenue through taxation. In a classical case such as Nigeria, in which the national fiscal budget is largely financed using hydrocarbon revenue, the DTS seemingly offers a better option for revenue sharing among the stakeholders—the resource owners and the Federal Government—than the current single upstream tax system. Our discussion in this paper bridges the gap between the divergent viewpoints on the taxation system in Nigeria by proffering a pathway. We suggest that the overall objectives of stakeholders could be achieved using either STS or DTS metrics if the mechanics in designing the fiscal system is better understood. This will lead to progressive application in achieving divergent expectations.

Royalty is a mechanism by which mineral owners – usually host government – obtain upfront revenue as soon as production begins from a petroleum lease or block. It can be received in cash or in kind and represents a part of front-loaded cost of doing business; it is tax deductible in oil and gas tax calculations. Economic rents extracted through royalty payments are usually not based on profits. This dampens the progressiveness of a fiscal regime and would normally have effects on investments and resource development economics. This paper presents a progressive royalty framework and investigates the impacts 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 (IAT) memorandum on the 2008 Petroleum Industry Bill 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. Logarithmic sliding scale royalty scheme is generally perceived to perform better than other schemes but our analysis shows that terrain and geology matter a lot. This implies that if the royalty scheme is tied to geology, then marginal field operators 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 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 an equitable performance outcomes for all stakeholders in the emerging new petroleum era.

Fiscal system is the basis for the estimation of take statistics ratio between Government and Contractor. This has been the case for the different versions of Nigeria's Royalty and Tax system and Production Sharing Contracts. Modifications in the currently proposed petroleum industry fiscal bill promise to ensure oil and gas availability, accessibility and affordability. Favorable upstream petroleum operations underlie the development and expansion of the midstream and downstream sectors. Fiscal incentives available to contractors make investment a worthwhile venture for both the government and contractor. The recently proposed petroleum industry fiscal bill (PIFB) 2017 is a favorable development because it is anticipated to reduce tax burden on investors, increase government take from royalty schemes and a dual tax system imposed on oil and gas projects. This paper applies a deterministic and stochastic cash flow model, analyzes the fiscal provisions of the existing royalty and tax system, production sharing contract and the proposed petroleum industry fiscal bill, 2017. Results from the model present a friendly royalty and tax deduction strategy in the proposed bill, which provides an incentive for investors to re-invest in the midstream and downstream sectors. However, the provision in the petroleum industry fiscal bill (PIFB) 2017 for royalty deduction during windfall is rather too fair at $50/bbl, considering a benchmark profitable oil price of $35/bbl during windfall. This paper suggests $35/bbl price for windfall threshold price for the additional $0.2 per dollar increase in oil price for royalty by value determination.

The paper aims to; estimate relative technical efficiency (RTE) for each of the Nigeria 32 active Operators using vDEA model, rank the performance of the Operators considering output orientation, categorize each of the Operators into its respective return to scale (RTS) group using Non-Increasing Return to Scale model (NIRTSM) and suggest necessary policies that could improve the performance of the Operators. The approach is based on variable return to scale assumption of DEA model framework (vDEA). Based on this, four variables were considered; two inputs, petroleum reserves in million BOE and Number of producing Wells and two outputs; total annual oil production in million BBLS, total annual gas production in million SCF. vDEA model assumes operational variability due to constraints such as: projects financing, competition, government policies, operational terrains, etc. A dual linear programming model (DLPM) is formulated and a Microsoft excel solver aided with a visual basic application (VBA) is used to generate RTE for each Operator simultaneously. RTS indexes are estimated using output oriented NIRTSM. The relationship between the two models' results is used to categorize each Operator into different production scale group. The empirical results reveal a decreasing trend in the Operators' RTEs from 2010 to 2016. Twelve (12) of the Operators were operating on efficient production frontier within the period under investigation. Based on this, Operators were classified into three different production scale group. Eight (8 or 25%) were operating on decreasing return to scale (DRTS), Six (6 or 19%) on constant return to scale (CRTS) while the remaining Eighteen (18 or 56%) were on increasing return to scale (IRTS). Significantly, it is discovered that more than 80% of the JV Operators have been operating on DRTS. Consequently, the paper provides information on RTEs of the 32 active upstream Operators in Nigeria considering more realistic assumptions as recommended, (Idowu and Iledare, 2018). Operators performance is ranked based on estimated RTE indexes as well as production maximization consideration. The paper proposes policies such as: splitting of JVs companies into two or more to minimize bureaucracies and facilitate new efficiency-oriented ideas, merging of companies under IRTS to enhance internal growth and embarking on aggressive reserves growth policy to increase the reserves base of the 6 Operators on CRTS.

The paper evaluates the impact of the single tax system at its current rate in comparison to the proposed dual tax system in the National Petroleum Fiscal Policy in Nigeria on project economic performances. The paper also expounds on the arguments between two schools of thought (single tax and dual tax proponents) towards understanding the rationale underlying the divergent viewpoints. The methodological approach applies the discounted cash flow modelling framework to evaluate the performances of terrain based projects using selected metrics such as internal rate of return (IRR), discounted payout (DPO), net present value (NPV) and government take (GT) under the two tax systems. It calibrates the unit technical cost (UTC) for typical deep water projects in Nigeria and imposes the current and proposed fiscal terms. Varying cost treatment options and alternative allowable/incentives are investigated in the modelling framework using global best practices. The paper concludes that whichever tax system is adopted, it is possible to achieve equivalent economic metrics. However, the dual tax system presents a better flexible option over the single tax system as one of the split rates – especially the hydrocarbon resource tax – could serve as an instrument to incentivize investment, promote conservation, expand resource base through technology innovation more easily without denying the mineral owner an outright revenue via taxation. In a classical case like Nigeria, where national fiscal budget is largely financed using hydrocarbon revenue, the dual tax system seemingly offers a better option for revenue sharing among the stakeholders – the resource owners and the Federal Government than the current single upstream tax system. This paper bridges the gap between the divergent viewpoints on taxation system in Nigeria by proffering a pathway. It suggests that the overall objectives of stakeholders could be achieved using the same metrics if the mechanics in designing a fiscal system is better understood. This will lead to progressive application in achieving the divergent expectations.

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.

The design of fiscal regime by oil producing government is usually tailored to capture high economic rent for the maximization of their citizen’s welfare. This has been the case of the royalty/tax system practiced in Nigeria, also known as the joint venture arrangement. The fiscal incentives under this system have been espoused to yield higher government take compared to the other fiscal systems practiced. Nevertheless, government participation in the joint venture arrangement through its NOC requires the government to provide funds for project development with cash call obligation. However, the NOC has defaulted, severally, in fulfilling its cash call obligations which has delayed several project developments. Thus, the recent government exit from JV cash call agreement is a favourable development that have created a vacuum as to how the joint venture operations would be funded and the impact on the economic metrics and the government take. It is against this background that we employed the use of a deterministic and stochastic cash flow model under 3 funding scenarios for the R/T system. Our empirical result shows that the impact of capital cost recovery yields a decrease in government take. The price of crude oil, royalty and profit petroleum tax were shown to have the highest impact on the government take. We concluded that despite the impact of the joint venture financing option on the government take statistics, the economic metrics yield higher profitability index thus making the project viable. Hence, we recommend that government considers a pseudo PSC or an overriding royalty funding arrangement in order to retain its participatory interest in the JV agreement without the obligation of cash call. Given that this funding option will impact the government take as shown in our analysis, the fiscal incentives used under this system should be reviewed and revised.

The risks and uncertainties associated with oil price volatility and its global economic impact recently is creating a new thinking in terms of hydrocarbon utilization and energy security. Petroleum rent seeking nations are re-evaluating their micro/macroeconomic policies towards budgeting and producers are restrategizing on the most efficient cost of extraction means for sustained development and production. Ensuing oil geopolitics and regional conflicts are also driving a new energy supply and demand route in meeting global energy demand. Consequently, this work proffers an energy model that helps to answer the microeconomic implications of oil price volatility on resource based economies. The model incorporates empirical data and estimated aggregate domestic utilization needs to proffer solution on appropriate energy security and sustenance policy to adopt given forecasts of domestic oil and gas production and imports. The research aim is to analyze the nexus of oil price and economic potentials, especially in Nigeria, with respect to the petroleum value chain. Analysis of the challenges and prospects of hydrocarbon utilization towards economic growth and understanding of the resource base, energy demand and supply mix including development strategy towards energy sustenance are portrayed. Empirical results reveals that increased domestic utilization of resources gives comparative economic advantage in the balance of trade; eliminate opaque subsidy product loss margin; increase transparent downstream refining; and enormous revenune recapture opportunites approximately 25%, ceteris paribus. Result also shows that Nigeria and Africa at large compete favourably in terms of resource base among the committee of nations. As a result, value creation, economic and pragmatic policy and strategy are plausible imperatives toward energy security and stability.

In the past four decades, Nigeria has made impact on the global oil and gas exploration and production industry. As one of the lead exporters of crude oil and natural gas in Africa, an oil production model which tracks oil exploitation process is imperative to facilitate good national economic planning and industry strategy. The impact of technological advancement, policy incentives and economics can be estimated from such petroleum production model. This paper reviews historical crude oil production in Nigeria; develops an empirical model to describe and explain the competing factors underlying its production patterns. The production model equations are formulated; with a non-linear curve fitting method to estimate the Hubbert's model parameters for Nigeria. The model is used to forecast future production outlook for Nigeria. At the currently estimated reserves of 37.2 billion barrels, the model results suggest that production rate should have peaked at 2.70 MMSTB/D in year 2010, and forecasted that the estimated ultimate recovery, at year end 2050, will be 65 billion barrels (~ cumulative production of 31.25 billion barrels up till 2012 plus current proven reserves of 37.2 billion barrels). It suggests that the nation had just produced 50% of its currently estimated proved reserves. The Hubbert model was accurate for forecasting US crude oil production, but its strict symmetry has received criticism from experts (Lynch, 2002) (Cavallow, 2004) (Iledare, 2000) who believe that the model underestimates future production which our experiences also confirm. We specified the nature of the errors which resulted in considerable deviations of production trends from the Hubbert model. We suggest however, alternative model for analysing the exploitation process in Nigeria in the form of successive curve re-fitting of Hubbert model to new production data from time to time to check the effect of new technology, economics or policy implementation on Nigeria's crude oil production.

For the purpose of this paper, reserves growth is classified into three main categories: new pool discoveries, reserves revision and reserves extension. For each category, there are distinct factors affecting positive and residual reserves growth. The paper shows that fiscal/policy incentives, crude oil price and modern technology are necessary conditions to expand petroleum reserves, thereby prolonging the end of petroleum era in Nigeria. The deepwater remain the most promising area for further significant reserves growth. Therefore, the existing Production Sharing Contract (PSC) deepwater field development projects will undoubtedly impact positively to the country's production and reserves blueprint toward the 40 billion and 4.0 MMBBL per day targets by 2020.

This paper presents a model of new petroleum reserves in the Gulf of Mexico OCS region from 1977 to 19981. The model has three distinct components: the effectiveness of drilling at finding reserves (drilling success rate), the effectiveness of successful drilling at adding new petroleum reserves (petroleum productivity rate), and the number of wells drilled to find new reserves (drilling rate). Each component is specified as a function of several competing factors to determine the extent to which each determinant affects reserve additions on the OCS. The model equations are estimated using OCS data on reserves and oil and gas wells drilled from 1977-1998. The empirical results indicate a statistically significant evidence of diminishing returns as drilling increases on the OCS. The estimated elasticities of oil and gas reserves additions with respect to resource depletion are both very elastic. However, the responsiveness of new oil and gas reserves to economic incentives is significantly inelastic for oil and gas reserves. The results show that the average impact of technical change, economic, resource depletion, and prospect highgrading on oil reserve additions is a net gain of about 9.2% per year between 1977 and 1998. However, the net annual average impact of these competing factors on new non-associated gas reserves is a decrease of 3.3 percent per year.

Perhaps no industry has witnessed a more cyclical activity than the petroleum industry! Oil and natural gas account for a substantial part, over 70 percent, of world energy demand and utilization beside the worldwide application of its by-products. It is the main source of foreign exchange earnings for many developing economies. Crude oil price volatility, especially in the recent past, has made decision-making and strategic planning extremely difficult for oil companies. Oil companies have responded to the low oil prices by reducing research and development budget, capital spending, and employment pattern. The operators are even more cautious than ever before in capital spending and expansion despite the current rising trend in crude oil prices. This paper uses the basic laws of demand and supply and the concept of elasticity as well as user cost relations to evaluate the responsiveness of oil industry activity to changes in oil and natural gas price from 1960 to 2000. It relies on some E&P industry performance measures to evaluate the state of the oil and gas industry in response to crude oil price variability and instability. The results show that the profit margin of the major operators have been on the decline since the advent of OPEC and so is the demand for labor in the industry. The consequences of price instability have led to mergers and acquisitions and internal re-organization in order to attempt to maximize profit in the past few years. Finally, the paper attempts to forecast future oil and gas prices and evaluate their effects on oil industry activity over the next decade using economic impact analysis and the economic concept of price elasticity.

The purpose of this paper is to apply a region-specific- hybrid model of oil and gas reserve additions to determine whether the negative impact of depletion on the finding rate of new reserves has been more than offset by the positive effects of technical progress and economic incentives in the US Gulf of Mexico OCS region. Our model results confirm expectation of diminishing returns in the rate of change of drilling productivity with respect to basin maturity. We also found strong evidence, to suggest that as technology improves over time, better drilling choices are made and the rate of change of drilling productivity with respect to incremental drilling rises with time. Overall, we found strong statistical evidence to suggest that the positive influence of technical progress and economic incentives on drilling productivity has been strong enough to offset the negative impact of resource depletion on the finding rate of oil and gas reserves in the US Gulf of Mexico OCS during our study period.

The current expanded role of smaller independent oil producers in the OCS has led to concern about the possibility of increased risk of accidents in E&P operations on the Gulf of Mexico OCS. In addition, questions have been posed concerning the effects of the Minerals Management Service`s (MMS) safety regulations and inspection program, firm size, and industry practices on the risk of accidents in E&P operations on the Gulf of Mexico OCS. The specific purposes of the study reported in this paper were to ascertain (1) whether any empirical justification exists for the widespread concern that an increase in independents relative share of E&P operations in the Gulf OCS region will be detrimental to safety, and (2) whether MMS policies and safety programs have reduced the frequency or severity of accidents on the OCS. Our statistical and descriptive analyses of data on accidents from MMS provide no statistical evidence to support the apprehension that an expanded role for independents in E&P activity constitutes any major threat to safety on the OCS. Further, the results of our econometrics analysis confirm the expectation that the more effective MMS inspectors are at detecting incidents of noncompliance the lower the rate of accidents onmore » the OCS is, ceteris paribus. In addition the results indicate that the variability in platform exposure years--cumulative age of operating platform--in comparison to other factors explains a significant portion of the variation in accidents per operating platform. That is, the platform aging process provides more opportunity for accidents than any other contributing factors. Our econometrics analysis also suggests that, if the other factors contributing to offshore accidents are held constant, the responsiveness of accident rate to drilling activity is inelastic while the response of accident rate to production activity levels is elastic.« less