Fiscal Analysis of Resource Industries
(FARI Methodology)

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This manual introduces key concepts and methodology used by the Fiscal Affairs Department (FAD) in its fiscal analysis of resource industries (FARI) framework. Proper evaluation of fiscal regimes for extractive industries (EI) requires economic and financial analysis at the project level, and FARI is an analytical tool that allows such fiscal regime design and evaluation. The FARI framework has been primarily used in FAD’s advisory work on fiscal regime design: it supports calibration of fiscal parameters, sensitivity analysis, and international comparisons. In parallel to that, FARI has also evolved into a revenue forecasting tool, allowing IMF economists and government officials to estimate the composition and timing of expected revenue streams from the EI sector, analyze revenue management issues (including quantification of fiscal rules), and better integrate the EI sector in the country macroeconomic frameworks. Looking forward, the model presents a useful tool for revenue administration practitioners, allowing them to compare actual, realized revenues with model results in tax gap analysis.


This manual introduces key concepts and methodology used by the Fiscal Affairs Department (FAD) in its fiscal analysis of resource industries (FARI) framework. Proper evaluation of fiscal regimes for extractive industries (EI) requires economic and financial analysis at the project level, and FARI is an analytical tool that allows such fiscal regime design and evaluation. The FARI framework has been primarily used in FAD’s advisory work on fiscal regime design: it supports calibration of fiscal parameters, sensitivity analysis, and international comparisons. In parallel to that, FARI has also evolved into a revenue forecasting tool, allowing IMF economists and government officials to estimate the composition and timing of expected revenue streams from the EI sector, analyze revenue management issues (including quantification of fiscal rules), and better integrate the EI sector in the country macroeconomic frameworks. Looking forward, the model presents a useful tool for revenue administration practitioners, allowing them to compare actual, realized revenues with model results in tax gap analysis.

I. Background

Mining and petroleum projects share several characteristics that distinguish them from other sectors of the economy, due either to their mere scale or to the intrinsic properties of the resources themselves.2 Over time, countries have tailored their fiscal regimes to address challenges associated with the inherent characteristics of EI and existing market conditions. These fiscal regimes (Box 1) usually diverge from the general tax system applicable to the rest of the economy and vary widely in structure, choice of fiscal instruments and rates, as well as in the way fiscal instruments interact with each other.

In practice, the interaction between different fiscal instruments and individual EI projects can produce effects that cannot be easily inferred from headline tax parameters. Moreover, comparing fiscal instruments individually is often not sufficient: they have to be evaluated as a package. Without some quantification, it is difficult to tell how two fiscal packages with otherwise identical terms compare with each other when all that differs is one item – for example, the rate at which capital costs can be deducted in calculating taxable income for corporate income tax (CIT) purposes; or, how these differences are amplified or diminished by variations in the underlying project profitability in reaction to changes in prices or costs.

Defining the EI Fiscal Regime

The fiscal regime for mining and petroleum (oil and gas) is the combined system of tax and non-tax instruments used to raise government revenue from natural resource extraction activity. It includes not only conventional instruments such as royalty and CIT, but also contractual schemes such as production-sharing or risk service contracts. Lump sum payments required upon granting of rights (commonly referred to as “signature bonus”) and production bonuses payable upon reaching a predetermined production level are also common.

The fiscal regime can further include instruments of state participation which have fiscal effect on the division of revenues even where held by a commercially operating state-owned enterprise. The fiscal regime may also comprise taxes, fees, levies and charges which accrue to the state by way of additions to input costs.

Mandated requirements that do not directly add to fiscal revenues may form part of the fiscal regime. These can include, for example, obligations to supply product to the domestic market at prices below export parity, or obligations to support acquisition of equity interests by designated citizens. Finally, the fiscal regime may be project-specific if some of its components are set in a contract, or sector-specific if it applies uniformly to all extractive projects.

Because of such interactions, the design and evaluation of fiscal regimes require detailed economic and financial analysis at the project level. To support its technical assistance (TA) work over the years, FAD has developed an analytical tool that allows project-based modeling and fiscal regime evaluation known as FARI.3 The FARI framework consists of a detailed, Excel-based discounted cash flow (DCF) model that operates on a project by project basis. The model inputs include production and cost profiles over the life of resource projects, economic assumptions such as prices, inflation and discount rates, financing arrangements, and the terms of the fiscal regime to be evaluated.

The analysis performed in FARI is done from the perspective of an investor from abroad, a normal situation for many resource-rich developing countries which depend on foreign investment to develop their EI sectors. The model helps determine how the net cash flows generated over the full life cycle of a project are divided between such an investor and the host government according to the terms of the fiscal regime. The government’s revenue arising from a project usually comes in the form of tax and non-tax instruments such as royalties, CIT, additional profit sharing mechanisms, final withholding taxes, state participation, and / or other EI related levies.4

FARI uses a suite of indicators to evaluate how different combinations of fiscal terms compare along relevant economic criteria (such as neutrality, revenue raising capacity, time profile of government revenue and progressivity), and against fiscal regimes in other jurisdictions—the calculations of which are discussed in detail in this manual. While FARI was originally designed as a tool for EI fiscal regime design and evaluation, it can also be adapted for revenue forecasting and tax gap analysis. Nevertheless, as any model, FARI represents a simplification of the reality and the results need to be interpreted with care. In particular, the model assumes full efficiency of revenue collection, no international tax planning, and no opportunity to deduct costs from one project against revenues from another in the absence of a well-defined fiscal boundary (or ring-fence) around the project.

This technical note offers a description of the FARI methodology as a quick reference guide for practitioners and country authorities dealing with EI taxation. The purpose is not to provide a detailed user guide to the model used in FAD advisory work, but to discuss the underlying thinking behind FARI’s main concepts and methodology. To this end, the manual is accompanied by a “stylized” version of the FARI model containing illustrative project examples, main fiscal calculations, and key economic indicators. The theory and principles behind the model’s fiscal analysis and indicators are discussed in detail in Daniel, Keen and McPherson (2010).

II. Fiscal Modeling of Resource Projects

In FARI, a project is defined as all necessary activities to commercially develop and exploit a mineral deposit or a petroleum field, collectively referred to as “upstream activities”. These activities span from exploration work undertaken to identify reserves, to the development and extraction of resources, to closure and rehabilitation of the production site once the resource has been depleted.

Economic modeling for fiscal regime design and evaluation is primarily concerned with upstream activities.5 However, FARI may also be adjusted to incorporate activities related to the enhancement of the extracted product through further processing and refining, beyond the upstream border. The project costs included are usually those directly related to the extraction process, but a facility to add estimated externalities, such as resource depletion or environmental costs, could be added when needed.

A. Stages in the Life of a Resource Project

The lifecycle of a resource (both mining and petroleum) project can be divided into four main phases: (i) exploration; (ii) development; (iii) production; and (iv) mine closure or field decommissioning (Figure 1).

Figure 1.
Figure 1.

Lifecycle of a resource project

Citation: Technical Notes and Manuals 2016, 001; 10.5089/9781513575117.005.A001

During the exploration phase, companies aim to identify and assess the geology of the areas of interest to determine the extent and nature of the resource in place. In mining, most of the costs are associated with conducting geophysical surveys, geological mapping to assess the potential for mineralization, and initial drilling to better understand the contents of the mineral deposit. If initial exploration is successful, further work is conducted to define the quality and quantity of the potential ore deposit, and to determine the mining method to extract the ore. This additional exploratory work, or “advanced exploration” as it is referred to in the industry, provides the first inputs to start planning the mine layout and to produce initial estimates to develop the resource project. In petroleum, after acquiring acreage and rights to explore for oil and gas, companies conduct seismic surveys to understand the geological and geophysical characteristics of the area. This process can take between three to five years, and if results are promising exploration drilling takes place. If petroleum is discovered, the company carries out an appraisal work program to assess the commerciality of the reservoir. It may take between four to 10 years, sometimes longer, from the time hydrocarbons are discovered to the time commercial production begins.6

Once commercially recoverable reserves are proven, the project advances to the development phase. For a mine, the development phase comprises all the activities required to establish permanent access to the ore body and carry out commercial production. During this phase the mine site is prepared, infrastructure is developed, mine construction – whether underground or on surface – takes place, and ore processing facilities are built. The development phase is the most capital intensive of all phases, and, depending on the size of the reserves, usually lasts between two to five years. For petroleum projects, development comprises the drilling of production and injection wells, as well as the building of surface facilities to transport, store, and measure the petroleum extracted. The development of an onshore field normally takes about a year, while offshore fields may take up to seven years depending on their size. During this phase, companies also need to prepare a field development plan (FDP) and submit it to the government for approval. The FDP describes the process by which petroleum will be extracted and produced, including expected production rates and solutions for the transportation of petroleum products (for example, the use of existing pipelines, construction of new flow lines, or an offshore terminal).

The production phase commences when the resource in the ground can be extracted and processed into a commercial product on a continuous basis, and can span over 20 years depending on the size of the reserves. In mining, this phase includes ore extraction, processing, and transportation. Production levels may be sustained over several years or even decades. However, there may be instances in which mining projects enter into periods of inactivity (also referred to as “care and maintenance”) due to changes in market conditions, operational problems, or as a result of political or social instability. In petroleum, this phase includes the different processes to extract oil and gas from reservoirs to the surface, separate crude oil from natural gas (if they occur together), and transport it to a pipeline network or a processing facility. Regardless of the production horizon of a petroleum field or mine, extraction rights are generally granted for a finite period of time, albeit with extension options in some places.

Finally, when reserves are depleted or production is no longer profitable mines are closed and petroleum fields are decommissioned. Depending on the legal dispositions of the jurisdiction where the project is located, companies may be required to restore the site to its original state. This process can be very expensive, and companies sometimes start to set aside funds to cover these costs when a certain percentage of reserves has been depleted.

The cash flows of a resource project mainly reflect the costs associated with the different phases described above and the production profile. While each mine has unique production and cost characteristics, it is not uncommon for mining projects to reach a peak production level early in the project life, and maintain this level until the end of the project (Figure 2a). This is because the rate of production is limited by the nameplate capacity7 of the processing plant. A mine cannot produce above this limit, unless additional capacity is built later on. Conventional gas projects also exhibit this relatively stable production profile, as gas processing facilities have limited capacity.

Figure 2.
Figure 2.

Illustrative Cash Flows: Resource Projects

Citation: Technical Notes and Manuals 2016, 001; 10.5089/9781513575117.005.A001

In contrast to the stable production rates usually found in mining and conventional gas projects, oil fields tend to have a bell-shaped production profile. After a production ramp-up period in the early years of the project, oil fields tend to reach peak production towards the middle of the project life, and then sustain a declining rate of production until the end of the project (Figure 2b). This profile is directly related to the intrinsic characteristics of petroleum reservoirs: in the beginning, pressure in the reservoir will sustain higher production rates, but as the resource in the reservoir gets depleted and pressure subsides, production rates also fall unless enhanced oil recovery is done (for example, by injecting gas back in the reservoir).8

B. FARI: A Framework for Fiscal Modeling

Because of these characteristics, fiscal regimes must be evaluated over the entire lifecycle of resource projects, from exploration9 to decommissioning of upstream facilities, in the case of a petroleum field; or to closure and rehabilitation in the case of a mine.10 This project-level approach estimates the government’s share of a resource project’s total pre-tax net cash flows (in effect, the economic rent11 when calculated in discounted terms at a rate equal to the minimum return to capital), as well as the effect of the interactions among the different parameters constituting the fiscal regime.

The FARI methodology discussed in this manual relies on a simple Excel-based DCF model. DCF is a valuation method traditionally used to calculate the net present value (NPV) of an investment. In this approach, the expected values of future cash flows are discounted back to a base year. As inputs, the model requires fiscal parameters, annual project costs and production volumes, economic assumptions (prices, inflation, interest and discount rates), as well as financing assumptions. The model calculations are performed on an annual basis (but could be adapted to shorter intervals if necessary), starting with the calculation of the project net cash flows before any fiscal impositions. Next, the model calculates each fiscal payment according to the fiscal regime parameters entered and the total government revenue from the project. The model then estimates several indicators that allow for the evaluation of the fiscal regime along relevant criteria (Figure 3).

Figure 3.
Figure 3.

Data flow in FARI modeling

Citation: Technical Notes and Manuals 2016, 001; 10.5089/9781513575117.005.A001

III. FARI: Model Inputs

A. Resource Project Data

In FARI, project data is entered in a predefined template which contains placeholders for production volumes and different categories of costs.

Production Profile

The production profile refers to the annual quantities of output from the project measured at the valuation point – for example, barrels of crude oil from an oil field, or tons of copper concentrate from a mine.12 Resource projects can produce multiple minerals, but from an economic perspective there is usually a clearly identifiable primary product.13 For example, a mine that produces copper as its primary product may also produce silver and molybdenum as by-products. Similarly, a petroleum field can produce both crude oil and natural gas, but from a project feasibility perspective only one of the two hydrocarbons is the primary product.14 The stylized models accompanying this manual make the assumption of a single commodity produced.

The stage of processing of a product obtained from a resource project is critical for any economic or fiscal analysis, and can have important implications for the calculation of royalties and other taxes (Box 2). In the case of mining, some projects may produce only ore which is then sold to a third party for smelting and further refining; while other projects may produce concentrate or more refined products, such as copper cathodes or iron ore pellets. Detailed information on the production process is thus important, in particular, identifying where the first delivery point is, how product prices are determined at that point, and what activities are subject to the EI fiscal regime.15

Cost Profile

The definition and classification of the fiscal treatment of the costs associated with each phase of a resource project – exploration, development, production, and decommissioning – is central to fiscal regime evaluation. Each phase entails a different set of cost categories that need to be properly treated from a fiscal point of view. For example, some costs may be depreciated over a certain number of years, while others may be expensed as incurred. In addition, some fiscal mechanisms may allow the deduction of certain costs, sometimes with an allowance in addition to the original costs incurred (also referred to as uplift), while others may not.16

Valuation Point(s) for Fiscal Purposes

Defining the valuation point is essential to determine the taxable base for the different fiscal instruments constituting the upstream fiscal regime. In practice, there may be as many valuation points as tax and non-tax instruments in the fiscal regime. For example, royalties may be levied on the value of production at the wellhead (or mine mouth), while CIT may be imposed on taxable income arising at the point of sale. In the case of fiscal instruments targeting resource rent, the valuation point is likely to be the physical point that separates upstream from midstream and downstream activities.

Once the valuation point is clearly defined, the corresponding price and any allowable deductions are also determined in reference to this point to calculate the tax base. For a simple ad-valorem royalty levied on the value of production at the wellhead or mine mouth, a “net-back pricing” approach is commonly used to determine the wellhead or mine mouth price (assuming sales take place later in the supply chain). The net-back price is calculated by starting with the value of the product at the point where it is first sold (at arm’s length prices), and then subtracting the estimated costs of moving the product from the wellhead or mine mouth to the point of sale.

As for production, project costs are gathered and recorded on an annual basis in the model. These annual sets of cost categories constitute the project’s cost profile. Accurate cost profiles are often more challenging to construct or obtain than production profiles. This is because cost estimates tend to change relatively more (both in magnitude and frequency) than production forecasts, as projects move from concept development to design and implementation.

FARI classifies project costs according to the phase of the project and their fiscal treatment (whether they are expensed or subject to a depreciation schedule). In the model, capital expenditure is classified as development costs (separated between tangibles and intangibles), and replacement capital.17 Tangible development expenditures, such as investments in property, plant, and equipment, may be subject to specific depreciation schedules (for example, the straight line method, units of production or declining balance). On the other hand, intangible development expenditures,18 such as drilling or pre-stripping19 costs, are often expensed as incurred or, in some cases, amortized by the units of production method. Replacement capital costs, which are also likely to be depreciated for tax purposes, reflect investments needed post-development to maintain the field or mine in operation, as machinery and equipment wear out and have to be replaced.

Similarly, FARI classifies operating costs into several categories:20 costs directly related to the extraction process (that is, the process of extracting mineral ore or hydrocarbons from the ground); costs related to processing, refining and beneficiation activities, such as liquid separation, washing, crushing and grinding; transportation costs incurred before the physical point where royalties or CIT are imposed (usually at the mine gate or at the free on board (FOB) export point); and other operating costs, such as selling, general, and administrative expenses.21 While all operating costs are commonly expensed as incurred, some fiscal regimes may limit how much of certain operating costs can be deducted in a year – hence the relevance of this cost breakdown in the model.

Since prices in FARI are commonly linked to international benchmarks, the model also allows for the deduction of transportation, refining, and processing costs incurred beyond the point where the fiscal instruments are levied. This separate category of costs is used not only to determine taxable income for CIT purposes (by netting back the international benchmark price to the point of CIT assessment) but also, in some cases, to calculate the royalty base.

Table 1 illustrates how production and cost data are entered in the model for two stylized mining and petroleum projects that will be used in the rest of this technical note. Data are entered for each production and cost category on an annual basis. If there is no production or cost in a particular year, the corresponding cell is left blank. The cells in yellow denote hard coded data entered into the model (user input). Further, in the examples showcased here, only costs related to successful exploration are included.

Table 1.

Production and Cost Data in Resource Projects

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Note: $mm const means millions of dollars at constant prices; 000 ounces means thousand ounces; Mbpd means thousand barrels per day; MMBbl means million barrels. These conventions are used throughout the document.

B. Economic Assumptions


The input price in the model must reflect the type of product generated and sold by the project. In FARI, price assumptions for petroleum products and most major minerals are often linked to benchmark or “spot market” prices. These prices are transparent, publicly available through commodities or futures exchanges22 and, in most cases, projections (going out up to five years) are relatively easy to obtain. In the stylized version of the model accompanying this manual the user can choose one constant price path in real terms, but other price options could be easily included.23


While the project cost data and price assumptions are entered in the model in real terms, the fiscal calculations are done in nominal terms by applying an assumed inflation factor. This approach ensures that capital depreciation and other tax-related calculations better reflect tax calculations in practice. Model results are then converted back to real terms for consistency of presentation. Inflation rates may in reality vary across different cost categories but for simplicity, FARI only uses one inflation rate24 which is applied uniformly to both price and costs.

Interest Rate

Another key input in the model is the real interest rate. This rate, usually set up with a margin over the long-term U.S. Treasury rate, is used with an adjustment for inflation to calculate various financing charges relevant to the fiscal calculations. For example, if a country requires companies to set up a decommissioning fund and such a fund is allowed to earn interest, the chosen interest rate is applied to calculate the interest gains made by the decommissioning fund. Another example is when the state participation is “carried” during certain periods of the project (commonly during exploration and/or development). If under this type of arrangement the state is required to repay with interest its portion of costs covered by the party developing the project (commonly referred to as the “contractor”), the chosen interest rate forms the basis for the interest charge associated with the carried interest. Finally, if the contractor finances part of its costs with debt, the chosen interest rate also forms the basis for the interest expense incurred as a result of this type of financing.

Discount Rates

The main model results are expressed in NPV terms to account for the time value of money, reflecting the time preferences (that is, a dollar today is worth more than a dollar tomorrow) and opportunity costs of the projects’ stakeholders (that is, the cost of borrowing or investing in an alternative project). Given that the results are presented in real terms, the discount rates are also expressed in real terms in the model. In general, selecting the right discount rates is difficult, especially when the government and the contractor have different preferences, risks, and liquidity needs.

The model uses a discount rate to calculate the NPV of government revenues, the average effective tax rate (AETR), and the government share of total benefits.25 Since these indicators are related to the government share of the project’s pre-tax cash flows, this discount rate ideally approximates the government’s real discount rate. Discount rates vary from country to country and, in general, these differences are likely to reflect differences in time preferences and opportunity costs (whether to spend now or in the future) among countries. For example, developing countries with urgent short-term needs are likely to have higher discount rates than advanced economies.

A second discount rate is used in the calculation of indicators quantifying the effect of the fiscal regime on the investor, such as the marginal effective tax rate (METR) and the project break-even price.26 Similar to the discount rate for the AETR and the share of total benefits, the discount rate for the METR ideally approximates the discount rate of private mining or petroleum companies in the country of analysis. This discount rate must reflect geological, political, and economic risks associated with the development of the resource project and can be proxied by the investor’s cost of capital (Box 3). There are many issues around the appropriate choice of discount rate and these are extensively covered in the literature.27 FARI takes a pragmatic approach and allows the user to enter the discount rate considered appropriate for the specific case analyzed.

C. Financing Assumptions

Project financing assumptions are simplified in the model and only pertain to the debt financed portion of the capital raised by the investor.28 The main objective in simulating debt financing costs is to determine the interest expense, if any, that would enter the calculation of CIT.

The model allows the option to select the percentage of pre-production development costs financed with debt. It is common for exploration costs to be fully financed with equity, while development costs financed with a combination of debt and equity. In selecting the portion of development costs financed with debt, any applicable thin capitalization rules must be taken into account.29 Additional debt parameters are also used in the model, such as the repayment period of the loan and the loan’s interest rate.30 Table 2 illustrates how the financial and economic assumptions are set up in the model. Again, all cells in yellow denote hard coded data entered into the model.

Table 2.

Financial and Economic Assumptions

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Estimating the Investor’s Cost of Capital

From an investor perspective, the cost of capital—that is, the rate of return required by the suppliers of capital—applied to a specific project depends on the characteristics of the project: the riskier the cash flows, the higher the cost of capital for the project. Leaving diversification issues aside, the most common approach to estimate the rate of return demanded by investors is to calculate the marginal cost of each source of capital and then take the weighted average of these costs. This approach is also known as the weighted average cost of capital (WACC). Once the WACC for the company31 as a whole has been calculated, the rate could be adjusted upward or downward to reflect the risk of a particular project. The WACC for a company, before any project-related adjustment, is calculated as follows:


where wd and we are the proportion of debt and equity respectively; rd and re are the marginal cost of debt (pre-tax) and equity respectively; and t is the company tax rate. Since in most countries interest on debt financing is deductible from income taxes, the pre-tax cost of debt is adjusted to account for this tax shield.

The cost of debt (rd) usually reflects the yield to maturity (or annual return) on the company’s debt (for example, its long term bond rate). As for the cost of equity (re), there are various ways to calculate it. Common approaches include the capital asset pricing model (CAPM), in which an equity risk premium is added to the risk-free return; and multifactor and build-up models in which a set of risk premia is added to the risk free rate to account for other risk factors.

IV. FARI: Fiscal Calculations

A. Project Cash Flows before Fiscal Impositions

After all the necessary economic and financial parameters are known and the project price and cost data have been entered, the model calculates the project pre-tax net cash flows. These constitute the base on which the fiscal calculations will be made later on.

The annual pre-tax project net cash flows are first calculated in constant dollars, as:


where the sales value of the mineral produced is given by the market price and volume of production (MarketPrice x Production); transportation and processing costs (Trans&Proc) represent costs incurred beyond the point where the title of the resource changes ownership (and where the CIT is levied); exploration costs (Expl) include the finding and appraisal costs specifically related to the project ; capital expenditure (Capex) includes development costs (both intangibles and tangibles) and capital replacement costs during production; operating costs (Opex) include costs directly related to the production process; decommissioning costs (DecommCosts) refer to the costs of cleaning up and restoring the mine site;32 and the subscript t stands for the year. Table 3 below illustrates the pre-tax project net cash flows, using constant prices, for a hypothetical gold mine. All cells in Table 3 are in grey, denoting they contain formulas instead of hard data.

Table 3.

Gold Mine: Pre-Tax Project Net Cash Flows (Constant Prices)

Pre-tax cash flows are initially calculated in real terms, using constant prices and constant costs.

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After applying the appropriate inflation index, the next block of data (Table 4) displays the pretax cash flows of the project in nominal terms. The values are obtained by multiplying the price and cost data in Table 3 by the assumed inflation rate of 2 percent (as entered in Table 2). This block of data is the foundation for the fiscal calculations in the model as it represents the base on which royalties, CIT, other profit or rent based taxes, and other levies are estimated.

Table 4.

Gold Mine: Pre-Tax Project Net Cash Flows (Market Prices)

Inflation assumptions are applied to both costs and prices to arrive to pre-tax cash flows at market prices.

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Note: $mm nominal means millions of dollars at market prices. This convention is used throughout the document.

Once the annual pre-tax net cash flows are determined, two important parameters can be calculated: the project NPV at given discount rates and the project internal rate of return (IRR) before tax. The project NPV is calculated using the formula:


where CFn is the net cash flow[s] in year n, and r is the discount rate. The latter accounts for the opportunity cost of capital and the premium required to take into account project or country-specific risks. The IRR is the discount rate at which the NPV of the cash flows becomes zero.33

The hypothetical gold mining project, given the market price and cost assumptions described above, is a profitable one on a pre-tax basis with a real return of 41 percent and NPV of USD508 million (on flows discounted at 10 percent34). Similar to the mining project, the petroleum project example is also profitable on a pre-tax basis, with a real IRR of 36 percent and NPV of USD1,021 million (on flows discounted at 10 percent). Tables 5 and 6 show the constant and nominal cash flows for the petroleum project.

Table 5.

Petroleum Field: Pre-Tax Project Net Cash Flows (Constant Prices)

Pre-tax cash flows are initially calculated in real terms, using constant prices and constant costs.

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Table 6.

Petroleum Field: Pre-Tax Project Net Cash Flows (Market Prices)

Inflation assumptions are applied to both costs and prices to arrive to pre-tax cash flows at market prices.

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The pre-tax net cash flows form a basis on which to measure the relative effect of the fiscal regime on the project. In general, a project is considered viable, on a pre-tax basis, if its NPV is positive; or if the IRR is higher than the company’s cost of capital or hurdle rate. However, since both the NPV and the IRR are likely to be lower when the fiscal regime is factored in, determining the viability of the project is done on a post-tax basis. In FARI, a project is considered viable when the post-tax NPV, using the assumed hurdle rate required by the investor, is not negative or the post-tax IRR is equal or higher than the investor’s discount rate.

The following two sections explain how different fiscal regimes for mining and petroleum impact the economics of the resource projects. In particular, the terms of the fiscal regimes determine when and what share of a project’s pre-tax net cash flows are allocated as revenue to the government. For example, part of the revenue generated by a project with the cash flow profile in Figure 4 will be allocated to the recovery of the original investment and to operating and replacement costs, the remaining net cash flows (the combined yellow and purple areas) being then divided between the investor and the government according to the terms of the fiscal regime. Two such fiscal regimes are discussed in the following sections: a tax/royalty system with application to mining; and a production sharing system with application to petroleum.

Figure 4.
Figure 4.

Illustrative Breakdown of Project Net Cash Flows

Citation: Technical Notes and Manuals 2016, 001; 10.5089/9781513575117.005.A001

B. Typical Calculations for a Tax/Royalty Regime

Tax/royalty schemes are more often found in the mining sector, generally comprising taxes on production (commonly known as “royalties”); CIT; and in some cases, additional rent or profits taxes which in practice come in various forms (such as variable income tax, tax surcharge on cash flows, or windfall taxes, to list a few).35 The government may also participate in the project either as a passive investor or by acquiring a carried interest.36 Indirect taxes, such as import duties and value added tax (VAT) can be substantial in specific situations, but are neither discussed, nor modeled here.37

In the model, the fiscal parameters are entered in a section at the top of the page. The first column of the yellow area in Table 7 illustrates the minimum set of parameters that would be required to set up a fiscal regime in the base case. This regime is assumed to consist of 5 percent royalty on sales value (assessed at the mine gate), 30 percent CIT, and 10 percent state participation in the form of free equity. A 15 percent withholding tax on dividend payments abroad also applies. Two alternative regimes containing variants of additional profits tax are further evaluated, and their parameters are entered in columns 2 and 3. Specifically, the second regime assumes a 20 percent surcharge on cash flows (calculated after CIT), while the third regime assumes a 20 percent resource rent tax payable after a nominal rate of return of 10 percent is achieved (on cumulative results net of CIT payment).

Table 7.

Fiscal Regime Parameters: Mining

Three mining fiscal packages are analyzed. Alternatives 2 and 3 build on the first regime by introducing a cash flow tax, and respectively a resource rent tax. The yellow background designates hard-coded inputs into the model.

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Royalties are levies on production, charged either as a fixed fee per unit of production (“specific” royalties) or as a percent of (a measure of) the value of production (“ad-valorem” royalties). The base on which royalties are applied can make a significant difference for government revenue.38

For the gold mining project discussed here, the royalty is assumed to apply ad-valorem on the value of the mineral at the mine gate, generically labeled in the model as “net revenue.” This value is calculated as the “gross value” of the mineral produced (that is, the sales value at the export point abroad) with deductions for (i) refining and smelting charges, (ii) transportation from the mine to the FOB delivery point, and (iii) freight from FOB to the location where the international benchmark price is quoted. These deductions are consolidated under transportation and processing costs (Tansp&Proc) in the formula below. This adjusted price used in the calculation of royalty may be different from the actual sales price used in the calculation of revenue for CIT purposes.39


Corporate Income Tax

The CIT is calculated on taxable income, defined as net revenue less allowable deductions: exploration costs40 (in this particular illustration, assumed capitalized and the deducted in full when production starts), intangible capital expenditure (assumed to be deducted in full), depreciation of capital expenditure, operating costs, and interest paid (up to the limit permitted by applicable thin capitalization rules, if any). Depending on the fiscal regime, the expensing or amortization of pre-production capital costs can start immediately or can be deferred until the beginning of production, hence the switch in the model (Table 7). Where contributions to a decommissioning fund are made in cash, they are usually also treated as a deduction. The royalty is a deductible expense from the income tax base. In the regime modeled here, losses at the end of each year are carried forward indefinitely until fully recovered, although some jurisdictions may impose limits either on the period of time such losses can be claimed in future tax years or on the maximum loss offset allowable in each year (in order to preserve a minimum tax base).


Additional Profits Taxes

Countries apply different fiscal mechanisms to capture project economic rents beyond what regular fiscal instruments, like royalty and income tax, are able to achieve. Two mechanisms illustrated here are the Surcharge on Cash Flows and the Resource Rent Tax.42 The key difference between this category of taxes and the CIT is that capital expenditure is deducted in full (thus, not depreciated) and interest is not explicitly allowed as a deduction from the base.43

The Surcharge on Cash Flows (SCF) is a tax on project cash flows applicable once the cumulative project net cash flows become positive, usually after deduction for royalty. When the surcharge tax is levied “after tax”, the net cash flows are further adjusted with a deduction for income tax paid in the year. Some regimes may also allow an uplift on the capital expenditure incurred during the development phase as further deduction from the net cash flows, to allow a minimum return on capital.

Modeling-wise, the SCF liability is the SCF tax rate multiplied by the positive balance at the end of each year, obtained by estimating net cash flows in the year and deducting any negative balance from the previous period (Table 8). When the end-year balance is positive and tax is paid in the year, the balance of accumulated cash flows is set to zero for the next year so that the same cash flows are not taxed twice (given that the cumulative negative cash flows up to that period have been offset in full). When the end-year balance is negative, the amount is carried in full to the next period.

Table 8.

Modeling Royalty and Profit/Rent Taxes

The royalty calculations are modeled first, followed by Corporate Income Tax. The Cash Flows Tax Surcharge and the Resource Rent Tax are also modeled for alternative regimes 2, and respectively 3.

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The Resource Rent Tax (RRT) is modeled in a very similar fashion as the SCF, with the only difference that the end-year negative balance is carried forward with an uplift, the equivalent of an interest rate. This is usually thought of as a minimum required return to investor or threshold above which economic rents are generated. When the accumulated negative cash flows are fully offset by revenues, the positive balance becomes taxable at the rate of the RRT.


Like the SCF, the RRT can be applied before CIT (in which case the RRT is deductible in calculating the CIT) or after CIT (in which case CIT paid is treated as a cash outflow). The example shown in Table 8 assumes that both the SCF and the RRT are paid on after-tax proceeds. As expected, the RRT payments occur later in time relative to the SCF, which is consistent with the idea of allowing the investor to not only recover their costs (as in the case of SCF) but also earn a minimum return on after-tax cash flows (cumulatively, from the start of the project), before the RRT is payable.

From a tax administration point of view, net cash flows can be calculated starting from the taxable income (before prior period losses and as reported on the tax return) with two basic adjustments. One needs to add back net financial cost and capital depreciation, and deduct capital expenditure in full to arrive to net cash flows after royalty.


In Table 8, this approach is illustrated in the adjusted taxable income for the SCF.

Withholding Taxes

Since the calculations in the FARI model are undertaken from the perspective of a foreign investor, the model accounts for withholding tax on dividend distributions to non-residents, assumed to be a final tax.44 The model takes a “residual dividend” approach in calculating the base for the dividend withholding tax (DWT), although the practice may differ significantly across companies and projects.45 In this approach, the assumption is that all the initial positive free cash flows to equity are allocated to the payment of the return of capital (i.e. the refund of the original equity injection in the project), with any residual cash thereafter distributed in full as dividends to shareholders. In the model, this latter segment triggers a tax obligation, and happens when the cumulative free cash flows from the beginning of the project to the current year become positive.

The withholding on dividend comes on top of all other taxes paid by the investor, thus further diminishing its net cash flows (Table 9). While withholding on income to shareholders is not a tax on the project itself, withholding on dividend distributions made to non-residents (assumed to be the investors in the resource project) is treated as a final tax from the perspective of the host government.

Table 9.

Withholding Tax and State Participation

Dividends paid to shareholders and distributed to the state on account of its participation in the project are both modeled as a percent of distributable cash, calculated as the net cash flows available after the recovery of the initial costs with exploration and development.

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