## wpiea2024089-print-pdf - REFERENCES

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### Glossary
- AETR: Average Effective Tax Rate
- CD: Capacity Development
- CIT: Corporate Income Tax
- CO2: Carbon dioxide
- DCF: Discounted Cash Flow
- EBITDA: Earnings before interest, depreciation, and amortization
- EI: Extractive Industry
- EMV: Expected Monetary Value
- FAD: Fiscal Affairs Department
- FARI: Fiscal Analysis of Resource Industries
- FAST: Flexible, Appropriate, Structured, Transparent
- FE: Free Equity
- GHG: Greenhouse Gas
- IMF: International Monetary Fund
- IOC: International Oil Company
- IRR: Internal Rate of Return
- JV: Joint Venture
- METR: Marginal Effective Tax Rate
- MOF: Ministry of Finance
- NOC: National Oil Companies
- NPV: Net Present Value
- PCT: Platform for Collaboration on Tax
- POB: Pay-on-Behalf
- PSC: Production Sharing Contracts
- ROR: Rate of Return
- RRT: Resource Rent Tax
- STB: Share of Total Benefits
- VAT: Value Added Tax

### I. Introduction — scope and purpose
- FARI (Fiscal Analysis of Resource Industries):
  - Project-level, cash-flow based modeling tool developed by IMF FAD for quantitatively evaluating EI fiscal regimes.
  - Maps project cashflows over time, applies fiscal instruments, and allocates cashflows among stakeholders (investors, government, and optionally financiers).
  - Emphasizes interaction among fiscal instruments: analyzing instruments individually can mislead policy makers.
  - Excel-based, mirrors investor project analysis, designed to be relatively simple once core concepts and data are available.
  - Uses: tax policy analysis, forecasting EI fiscal revenues, assessing revenue collection risks (with modifications).
- IMF application:
  - Uses FARI in capacity development (CD) and training; published updated mining and petroleum models in 2021.
- Paper scope:
  - Describes harnessing FARI to analyze fiscal regimes, complementing IMF (2016) Technical Note.
  - Sections: preconditions for effective fiscal regime analysis; features of key EI fiscal mechanisms; comparisons of comprehensive fiscal regimes and FARI applications.

### II. The Groundwork for Fiscal Regime Analysis

#### A. Ensuring a Conducive Institutional Environment
- Typical institutional responsibilities:
  - MOF: designs general tax regime.
  - Revenue authority: administers and collects taxes.
  - Sectoral mining/petroleum ministry or regulator: grants/supervises licenses and PSCs; may oversee royalties, fees, and state participation.
  - NOCs: common in petroleum as holders of state participation and sometimes administer production sharing; less common in mining.
- Risks of fragmentation:
  - Undermines holistic fiscal regime analysis, administrative oversight, macro-fiscal management, data collection and sharing.
  - Increases risk of losing sight of whole-of-regime impacts and interactions among fiscal instruments.
  - Potential misalignment when sectoral agencies or NOCs advocate incentives or higher state participation that conflict with other fiscal instruments.
- Recommended mitigation:
  - Establish inter-agency working groups with two levels:
    - Senior policy group: sets fiscal strategy, interrogates model assumptions and inputs, feeds results into government-wide decision-making.
    - Technical modeling group: collects data, constructs, quality assures and maintains models, and presents findings to senior officials.

#### B. Configuring Fiscal Models
- Core FARI functionality and tradeoffs:
  - Compares outcomes under alternative fiscal regimes applied to individual EI projects; adaptable for revenue forecasting, contract negotiations, compliance risk assessment.
  - Design tradeoff: accuracy versus simplicity depending on purpose.
  - Transparency priority: users must follow calculations, find errors, and update models.
- Mining vs petroleum model key differences:
  - Petroleum model: assumes unincorporated joint venture; includes production sharing mechanisms, production-based bonuses, and EMV for exploration decisions.
  - Mining model: assumes an incorporated (resident) subsidiary of an offshore international mining company; does not emphasize EMV and exploration features to same extent.

#### C. Data Requirements
- Fiscal regime analysis:
  - Can use stylized project data representative of country projects; sources include approved domestic or similar foreign projects, feasibility studies, technical reports, company disclosures.
- Revenue forecasting requires:
  1. Historical cost, production and sales data, and taxes paid for model reconciliation.
  2. Projections of costs and production for the forecast period or remaining life of project.
  3. Detailed fiscal terms applicable to each project.
  - Forecast horizon: typically 3-5 years for budgeting; should be prepared in longer-term sector outlook context.
- Compliance risk assessment:
  - Backward-looking with granular project history (cost recovery statements, asset registers, production volumes, realized prices, tax data).
- Contract negotiations:
  - Investors often provide models assuming full equity financing; governments must evaluate debt financing impacts on revenues — a key FARI feature.
- Discount rate considerations:
  - Governments often prefer a lower discount rate for intergenerational considerations.
  - FARI simplifies by assuming a common discount rate for investors and government to allocate discounted project costs and benefits consistently and enable cross-country comparisons.

### III. Fiscal Regime Analysis for Policy Evaluation and Design

#### A. Tax Policy Objectives and Measures
- Fiscal regime objectives and corresponding measures:
  1) Capacity to generate revenues
     - Measure: AETR: share of project NPV captured by the fiscal regime.
     - Early revenue: assess AETR at higher discount rate or minimum share from start of production (effective royalty).
     - Note: Progressive elements maximize revenue collections; regressive elements reduce capacity.
     - Production sharing footnote formula preserved verbatim in source text.
  2) Neutrality
     - Measures: compare post-tax breakeven price to pre-fiscal-regime breakeven price; calculate METR.
  3) Adaptability and progressivity
     - Progressive regime: stable or increasing government share (AETR) as investor returns exceed hurdle rate; first-best is constant marginal tax rate above minimum return (IMF 2018).
     - Common second-best: combine regressive royalties with progressive RRT to balance early revenues and progressivity.
  4) Attractiveness to investors
     - Investor priorities: discounted after-tax value, payback period, breakeven price, stability of fiscal terms.
     - Ease of administration matters; FARI does not include specific indicators for ease of administration.
- Policy trade-offs:
  - No one-size-fits-all; combination of ad valorem royalty, CIT, and RRT often appealing:
    - Royalty: revenue whenever production positive.
    - CIT: taxes normal return to equity.
    - RRT: targets economic rent.
  - Equivalent fiscal outcomes possible via PSCs or hybrids.

### Box 1 — Key Indicators Used in FARI Analysis (Investor- and Government-focused)
- Investor-focused indicators (definitions preserved):
  - Post-tax NPV: discounted PV of investor net cash flows; formula and variables preserved verbatim.
  - Post-tax IRR: discount rate at which NPV = 0; model also calculates return to equity by netting lender cash flow.
  - Payback Period: cumulative cash inflows equal cumulative outflows; variants noted (discounted/undiscounted, leveraged/unleveraged).
- Government-focused indicators:
  - AETR: NPV(Gov Revenue) / NPV(Revenue − Exploration − Dev&Replacement Capex − Opex − Decomm); interpretation preserved.
  - METR: (Pre-Tax IRR − Post-Tax IRR) / Pre-Tax IRR; reflects tax burden on marginal viability.
  - Breakeven Price: minimum price to yield specified post-tax return; model determines by iteration.
  - Progressivity: ability to capture larger share in highly profitable projects while reducing burden in low profitability ones; analyzed by plotting AETR across pre-tax returns.
  - STB (Share of Total Benefits): operating profits without deducting cost of capital; used to compare progressivity.

### Box 2 — Royalty Valuation Points and Fiscal Instrument Features
- Valuation points and reconciliation:
  - Stylized value chain A to F; prices reconciled by adding/subtracting costs (e.g., mine gate to FOB).
  - Reconciliation imperfect due to processing, market dynamics, inventories, capacity constraints.
- Royalty structure and interactions:
  - Ad valorem royalties: flat percentage or variable by price/production/product type.
  - Tradeoffs: variable rates can add progressivity but are imperfect proxies for profitability; monitoring and adjustment required.
  - Tax treatment interactions:
    - Royalties deductible when determining CIT base; non-deductibility increases CIT liabilities and AETR.
    - Royalties payable from start of production; tax rules should allow resulting tax losses to be carried forward.
    - In PSCs, cost-oil limit calculation relative to royalties matters.
- Numerical illustration (preserved):
  - Gold project example: making a 5 percent royalty non-deductible increases discounted AETR by 3 percentage points (assuming a 30 percent CIT rate); equivalent deductible royalty to match revenues would be 7 percent.
- Royalty options in FARI:
  - Flat royalty; price-based royalty with two rates and optional inflation indexing; deductibility of transport costs can reduce regressivity.
  - Variable rates applied to full value create "cliff" effects; applying to incremental value above threshold smooths rate.
- Corporate Income Tax (CIT) modeling notes (preserved):
  - CIT components: exploration costs, royalties, operating costs, interest payments (subject to limits), depreciation allowances.
  - Ring-fencing assumed at license/contract area.
  - Depreciation: five cost categories; three capitalized; single straight-line depreciation chosen to approximate country asset types.
  - Loss carry-forward: published FARI assumes indefinite carryforward.
  - Decommissioning: provisions and tax deductibility reconciled with final rules.
  - Debt financing: FARI includes debt financing with parent company providing debt to evaluate parent outcomes.
  - Withholding taxes: modeled as deductions unless more detail justified; economically equivalent to free government participation in an incorporated JV in some cases.
  - CIT rates: statutory rates vary; Global Anti-Base Erosion Model Rules (Pillar Two) weaken case for reduced CIT rates.
- RRT and pure rent taxes:
  - Pure rent (Brown) tax: refunds negative cashflows; equivalent to government participation via fully paid equity.
  - Cashflow RRT: negative cashflows carried forward with uplift; no deduction for financing costs; immediate expensing benefits time value.
  - Interaction with CIT: pre- vs post-CIT application matters; post-CIT RRT lowers administrative simplicity but can act as backstop to CIT leakage.
  - Design challenges: correct imputed rate (hurdle) critical; single vs multi-tier rates tradeoffs.
- Production Sharing Contracts (PSCs) features:
  - Profit petroleum = net revenue after royalties − cost petroleum.
  - Cost recovery: immediate expensing for capital often with aggregate recovery limit (percentage of production after royalties).
  - Sharing mechanisms: DROP, R-factor, ROR—each uses different proxies and tradeoffs; sliding scale interpolation avoids cliff effects.
  - Pay-on-behalf (POB): contractor subject to CIT on profit oil; advantages include single audit and fiscal stability; requires tax authority audit participation.
- State participation forms and implications:
  - Working interest: state contributes costs as incurred; conceptually akin to Brown tax; most progressive if financed from cash.
  - Carried interest: state financed by others with repayment from production; carry can be equivalent to RRT.
  - Free equity: state receives equity without contributing costs; behaves like dividend withholding tax and is most regressive.
  - Financing dimensions of carry: quantum, interest "price", repayment pattern.
  - Entity treatment: incorporated JV taxed as separate entity; unincorporated JV partners taxed on shares.
  - FARI assumptions: mining model assumes incorporated JV; petroleum model treats JV partners taxed separately; NOC allocations modeled with carries but limited further tax unless required.
- Carbon tax design and effects (preserved specifics):
  - Scope definitions: Scope 1 (direct), Scope 2 (purchased electricity), Scope 3 (post-fence combustion).
  - FARI: carbon tax implemented on Scope 1 in petroleum model; emissions-intensity examples range from 3 to 30 g CO2 eq/MJ.
  - Example equivalence: 16 g CO2 eq/MJ = 0.1 tonne per barrel of oil equivalent; USD 50 per tonne carbon tax at 16 g CO2 eq/MJ => USD 5 per barrel tax.
  - Tax rate guidance: phase in; Stern and Stiglitz (2017) reference USD 40 to 80 in 2020 and USD 50-100 by 2030.
  - Deductibility: general view that taxes on negative externalities should be deductible and recoverable; non-deductible tax calibrated to match deductible effects.
  - Stylized oil project example (preserved):
    - USD 75 per tonne carbon tax:
      - Low emissions project (3 g CO2 eq/MJ): investor IRR falls by 1 to 2 percentage points relative to no tax.
      - High emissions project (30 g CO2 eq/MJ): investor IRR falls to 7 percent (19 percentage points lower) when carbon tax not deductible or recoverable.
      - Production cessation: high-emissions project stops five years earlier when tax not deductible/recoverable and one year earlier when recoverable and deductible; low-emissions project unaffected in example.
  - Note: FARI does not automatically include behavioral responses to carbon price.

### Box 3 — Energy Transition Impacts and Regime Design
- Macro effects:
  - Hydrocarbon and coal demand, investment, and prices expected to fall (IEA, 2021b), increasing competition for upstream investment and lowering economic rents.
- Policy trade-offs:
  - Rebalance from distortive to progressive instruments (reduce royalties, increase profit-based taxes) to attract investment versus maintain production-based taxes to maximize revenue from existing projects.
  - Risks: profit-based taxes harder to administer; production-based taxes can accelerate decommissioning and deter new investment.
- Non-fiscal considerations:
  - Position on cost curve and presence of state-owned companies matter for investment prospects and negotiation timelines.
- Mineral demand for transition technologies:
  - Increased mining for rare earth elements, copper, nickel, lithium, cobalt, manganese.
  - Fiscal and geological policy implications: encourage exploration, timely development; risk of rushed negotiations.
- VAT modeling and effects in FARI (preserved assumptions and conclusions):
  - FARI assumes all production exported; investor requires refunds on input VAT.
  - Four modeling assumptions listed verbatim regarding refund treatment and scheme exclusions.
  - Economic findings:
    - VAT does not affect government take or investor profitability if refunds immediate.
    - Investor IRR declines as refund delay lengthens; timely refunds improve competitiveness.
    - Where policy refunds VAT, VAT receipts may be excluded from estimates of total regime revenue.
- Comparative mining example (preserved regimes and findings):
  - Gold project parameters: pre-tax IRR 28 percent; project NPV nearly US$ 600 million; gold price US$ 1500/ounce used.
  - Four illustrative regimes with main parameters:
    - Regime 1: Royalty + CIT — Royalty 7 percent (net, deductible); CIT 25 percent; RRT: - ; State participation: -.
    - Regime 2: High royalty / low CIT — Royalty 9 percent (net, deductible); CIT 21 percent; RRT: - ; State participation: -.
    - Regime 3: Low royalty + high CIT /+ RRT — Royalty 2 percent (net, deductible); CIT 26 percent; RRT 20 percent (20 percent uplift on negative cashflows); State participation: -.
    - Regime 4: Royalty + CIT + SP — Royalty 5 percent (net, deductible); CIT 20 percent; RRT: - ; State participation: 10 percent free equity.
  - Key comparative findings:
    - At gold price US$ 1500/ounce, AETR NPV is 40 percent for all four regimes.
    - Revenue timing differences:
      - Regime 2 is frontloaded; Regime 3 backloaded.
      - All start generating revenues from first year of production (2025).
      - Regime 2 generates 5 times higher revenue in year four of production than Regime 3.
      - From year seven onward, Regime 3 generates highest revenue until production ends.
      - Regime 1 and Regime 4 have nearly identical revenue profiles (assuming full dividend distribution by government entity).
    - Progressivity and breakeven prices (to achieve 10 percent after-tax IRR in real terms):
      - Regime 2 most regressive.
      - Regime 3 relatively flat progressivity curve across outcomes down to pre-tax IRR 15 percent.
      - Breakeven prices:
        - Regime 2: US$ 1032 per ounce
        - Regime 1: US$ 1,004 per ounce
        - Regime 4: US$ 1,017 per ounce
        - Regime 3: US$ 968 per ounce (lowest breakeven)

### Annex I — Practical Guidance (model operation and customization)
- Adding a new fiscal regime:
  - User inputs in yellow cells on “FiscalModel” (to the right of column J); each input column is a regime; regime name in row 11.
  - FARI can store up to 40 regimes; calculations performed for regime selected in cell C6 of “Dashboard”.
  - Use index-match formula; maintain formulas in column F; entering inputs directly into column F causes errors.
  - Steps: enter values into empty regime column; set regime name in cell C6; add regime name to top data table; press F9; update breakeven via “Breakeven” button.
  - Sources for fiscal regime information include resource contracts, government websites, IMF publications, regulatory filings, consultancy summaries, company disclosures.
- Adding a new project:
  - Required data: production (petroleum daily rate in thousands bpd; mining annual volumes in thousands units) and costs in millions of US$ in real terms of first model year.
  - Cost disaggregation into six categories; transport/refining costs post-fiscal point.
  - Procedure: copy existing project worksheet, rename, update assumptions, link mineral in “Translate”, add sheet name to “Inputs”, select project in cell C7 of “Dashboard”.
  - Do not add rows above decommissioning costs row.
- Key assumptions:
  - Commodity price: use long-term expected international benchmark in real terms; alternatives allowed.
  - Inflation: long-term CPI for US dollars; suggested source US Federal Reserve.
  - LIBOR (real terms): historic benchmark until 2023; transition to SOFR noted.
  - Discount rate: entered in real terms; conversion formula provided; public model assumes single discount rate.
  - Hurdle rate: used for breakeven; company-specific.
  - Proportion of development costs borrowed: public config assumes parent company provides debt; typical assumption around 70 percent.
  - Repayment period: varies, roughly five to fifteen years.
  - Loan interest rate: nominal, project specific; must reflect project and country risk premium.
- Adding fiscal instruments/customization (steps preserved):
  1. Add inputs in yellow cells above “bottom of fiscal regime parameters” in “FiscalModel”; preserve column F index-match.
  2. Add fiscal calculations in relevant “FiscalModel” section; reference column F parameters; include reconciliation checks.
  3. Link mechanism across model: include deduction in CIT, add revenue to consolidation, link to reconciliation checks, add to “Charts” and “Dashboard”.

### Annex II — Documentation of Modeling Assumptions (baseline and regimes)
- A. Project economics in baseline (preserved figures):
  - Petroleum: Project 800MMbbl_A
    - Production: 800 million barrels
    - Production years: 27 years
    - Project unit costs US$ (2021): 38.5/barrel
    - Pre-tax IRR (real): 32 percent
    - Pre-tax NPV US$: 9,994 million
  - Mining (Gold): Project Gold (2MMoz)
    - Production: 2,000, ounces
    - Production years: 17 years
    - Project unit costs US$ (2021): 723/ounce
    - Pre-tax IRR (real): 28 percent
    - Pre-tax NPV US$: 505 million
  - Mining (Iron Ore): Project IronOre (250MMt)
    - Production: 250,000,000 metric tonnes
    - Production years: 21 years
    - Project unit costs US$ (2021): 43/dry metric tonne
    - Pre-tax IRR (real): 14 percent
    - Pre-tax NPV US$: 1,113 million
  - Mining (Coal): Project Coal (250MMt)
    - Production: 250,000,000 metric tonnes
    - Production years: 28 years
    - Project unit costs US$ (2021): 39/ metric tonne
    - Pre-tax IRR (real): 22 percent
    - Pre-tax NPV US$: 1,105 million
- B. General assumptions (preserved):
  - Commodity price in baseline scenario:
    - Oil US$ 55/barrel
    - Gold US$ 1500/ounce
    - Iron US$ 80/dry metric tonne
    - Coal US$ 90/metric tonne
  - Discount rate in real terms: 8 percent
  - Inflation rate: 2 percent
  - Real LIBOR (benchmark interest rate): 0 percent
  - Decommissioning provisioning:
    - Petroleum: Fund with provisioning starting at 50 percent of depletion
    - Mining: Fund with provisioning starting at 60 percent of depletion
  - Debt financing:
    - Petroleum: 70 percent of negative cashflows during development financed by parent loan; loan interest rate 3 percent over nominal benchmark; repaid over 10 years.
    - Mining: 70 percent of negative cashflows during development financed by parent loan; loan interest rate 5 percent over nominal benchmark; repaid over 5 years.
- C. Fiscal regime assumptions (selected regimes preserved verbatim)
  - Petroleum fiscal regimes (examples preserved):
    - Royalty: 8 percent, net base; CIT 30 percent; exploration costs expensed; development costs depreciated over 5 years from start of production; RRT: 40 percent above hurdle rate of 15 percent with CIT deductible.
    - DROP PSC: Royalty 8 percent, net base; CIT 30 percent; cost recovery limit 80 percent; DROP tiers Tier 1: 20 percent DROP <= 20 kbopd; Tier 2: 30 percent DROP > 20 and <=70 kbopd; Tier 3: 40 percent DROP > 70 and <=120 kbopd; Tier 4: 50 percent DROP > 120 and <=170 kbopd; Tier 5: 60 percent DROP > 170 kbopd.
    - R-factor PSC: Royalty 6 percent, net base; CIT 30 percent; cost recovery limit 80 percent; R-Factor tiers Tier 1: 20 percent R-Factor <= 1; Tier 2: 30 percent R-Factor > 1 and <=2 kbopd; Tier 3: 40 percent R-Factor > 2 and <=3 kbopd; Tier 4: 50 percent R-Factor > 3 and <=4 kbopd; Tier 5: 60 percent R-Factor > 4 kbopd.
    - R-factor PSC; carbon tax deductible: Royalty 6 percent net base; Carbon Tax US$ (2021) 75/tonne of CO2 eq (real), recoverable for production sharing and deductible for CIT; CIT 30 percent; cost recovery limit 80 percent; R-Factor tiers as above.
    - R-factor PSC; carbon tax not deductible: Royalty 6 percent net base; Carbon Tax US$ (2021) 75/tonne of CO2 eq (real), not recoverable and not deductible; CIT and tiers as above.
    - R-factor PSC with VAT refund variations: Royalty 6 percent net base; VAT 20 percent with 80 percent of CAPEX and 20 percent of OPEX subject to VAT; refund immediate / refund 2 years delay / refund 4 years delay / no refund.
  - Mining fiscal regimes (examples preserved):
    - Royalty (gross, deductible) + CIT: Royalty 5 percent gross base, CIT deductible; CIT 30 percent; exploration expensed; development costs depreciated over 5 years.
    - Royalty (gross, non-deductible) + CIT: Royalty 5 percent gross base, not CIT deductible; CIT 30 percent; exploration expensed; development costs depreciated over 5 years.
    - Higher royalty (gross, deductible) + CIT: Royalty 7 percent gross base, CIT deductible; CIT 30 percent; exploration expensed; development costs depreciated over 5 years.
    - Price-based royalties: e.g., 5 percent below US$ 100/dry metric tonne, 10 percent above US$ 100/dry metric tonne (gross base), with or without indexing.
    - CIT only variants: CIT 30 percent with development costs depreciated over 1 year / 3 years / 5/7 years as specified.
    - Low royalty + low CIT /+ RRT: Royalty 5 percent net base, CIT deductible; CIT 20 percent; RRT 20 percent above hurdle rate of 20percent with CIT deductible.
    - State participation constructs:
      - FE-10: 10 percent free equity
      - CI-10: 10 percent carried interest, carry repaid out of 100% of state participation cashflows, carry loan available until 10th year of production at % percent over the nominal benchmark interest rate.
      - WI-10: 10 percent working interest

*Content extracted from wpiea2024089-print-pdf - REFERENCES (IMF Working Paper).*

### REFERENCES .............................................................................................................

### wpiea2024089-print-pdf - REFERENCES .............................................................................................................

### Glossary
- AETR: Average Effective Tax Rate  
- CD: Capacity Development  
- CIT: Corporate Income Tax  
- CO2: Carbon dioxide  
- DCF: Discounted Cash Flow  
- EBITDA: Earnings before interest, depreciation, and amortization  
- EI: Extractive Industry  
- EMV: Expected Monetary Value  
- FAD: Fiscal Affairs Department  
- FARI: Fiscal Analysis of Resource Industries  
- FAST: Flexible, Appropriate, Structured, Transparent  
- FE: Free Equity  
- GHG: Greenhouse Gas  
- IMF: International Monetary Fund  
- IOC: International Oil Company  
- IRR: Internal Rate of Return  
- JV: Joint Venture  
- METR: Marginal Effective Tax Rate  
- MOF: Ministry of Finance  
- NOC: National Oil Companies  
- NPV: Net Present Value  
- PCT: Platform for Collaboration on Tax  
- POB: Pay-on-Behalf  
- PSC: Production Sharing Contracts  
- ROR: Rate of Return  
- RRT: Resource Rent Tax  
- STB: Share of Total Benefits  
- VAT: Value Added Tax

### I. Introduction
- Mining and petroleum projects are distinguished by scale, location-specific immobility, high sunk costs, long production periods, pervasive uncertainty, and resource exhaustibility (see IMF (2010) discussion).
- Extractive industry (EI) fiscal regimes commonly:
  - Diverge from the general tax system.
  - Vary in structure, choice of fiscal instruments and rates, and interactions among instruments.
- FARI (Fiscal Analysis of Resource Industries):
  - Is a project-level, cash-flow based modeling tool developed by IMF FAD for quantitatively evaluating EI fiscal regimes.
  - Maps project cashflows over time, applies fiscal instruments, and allocates cashflows among stakeholders (investors, government, and optionally financiers).
  - Emphasizes that interaction among fiscal instruments can produce non-obvious effects; analyzing instruments individually can mislead policy makers.
  - Is Excel-based, designed to be relatively simple once core concepts and data are available, and mirrors investor project analysis.
  - Can inform tax policy analysis, forecast EI fiscal revenues, and assess revenue collection risks with modifications.
- IMF application:
  - Uses FARI in capacity development (CD) and training.
  - Published updated mining and petroleum models in 2021.
  - Internal FARI models used for CD are more comprehensive than published models but share core cashflow modeling concepts and evaluation metrics.
- Paper scope:
  - Describes harnessing FARI to analyze fiscal regimes, complementing a 2016 Technical Note (IMF 2016).
  - Section breakdown: Section 2 - preconditions for effective fiscal regime analysis; Section 3 - features of key EI fiscal mechanisms; Section 4 - compares comprehensive fiscal regimes and demonstrates how FARI informs policy.

### II. The Groundwork for Fiscal Regime Analysis

#### A. Ensuring a Conducive Institutional Environment
- Typical institutional arrangement:
  - MOF: designs general tax regime.
  - Revenue authority: administers and collects taxes.
  - Sectoral mining/petroleum ministry or regulator: grants/supervises licenses and PSCs; may oversee royalties, fees, and state participation.
  - NOCs: common in petroleum as holders of state participation and sometimes administer production sharing; less common in mining.
- Risks from fragmented responsibilities:
  - Undermines holistic fiscal regime analysis, administrative oversight, macro-fiscal management, data collection and sharing.
  - Increases risk of losing sight of whole-of-regime impacts and interactions among fiscal instruments.
  - Potential misalignment when sectoral agencies or NOCs advocate incentives or higher state participation that conflict with other fiscal instruments.
- Recommended mitigation:
  - Establish well-functioning inter-agency working groups or committees with two levels:
    - Senior policy group: sets fiscal strategy, interrogates model assumptions and inputs, feeds results into government-wide decision-making.
    - Technical modeling group: collects data, constructs, quality assures and maintains models, and presents findings to senior officials.

#### B. Configuring Fiscal Models
- Core FARI functionality:
  - Compares outcomes under alternative fiscal regimes applied to individual EI projects.
  - Can be adapted for revenue forecasting, budget outlooks, contract negotiations, revenue administration risk assessment, and compliance activities.
- Model design tradeoffs:
  - Balance accuracy versus simplicity depending on purpose (pedagogical versus compliance-focused models).
  - For sectors with many projects, model large revenue-critical projects individually and smaller projects with simplified approaches.
  - Transparency is a priority so users can follow calculations, find errors, and update models (see Annex III on transparency principles).
- Differences between mining and petroleum FARI models:
  - Commercial structures:
    - Petroleum model: assumes unincorporated joint venture.
    - Mining model: assumes an incorporated (resident) subsidiary of an offshore international mining company.
    - This affects fiscal calculations, particularly where government has direct state participation.
  - Production sharing and production-based bonuses:
    - Common in upstream petroleum; petroleum model includes production sharing mechanisms and production-based bonuses.
    - Petroleum model includes Expected Monetary Value (EMV) as a metric for exploration decisions; mining model does not include these features to the same extent.

#### C. Data Requirements
- Fiscal regime analysis:
  - Can use stylized project data representative of country projects.
  - Data sources: recently approved domestic projects or similar foreign projects, feasibility studies, technical reports, company disclosures, for-profit data providers.
- Revenue forecasting:
  - Requires detailed historical information and medium-term projections for projects in or near production, including:
    1. Historical cost, production and sales data, and taxes paid for model reconciliation and, if applicable, work plans and cost recovery statements.
    2. Projections of costs and production for the forecast period or remaining life of project (e.g., updated life of mine plans).
    3. Detailed fiscal terms applicable to each project.
  - Forecast horizon typically short- to medium-term (3-5 years) for budgeting, but should ideally be prepared in the context of a longer-term sector outlook.
  - Forecasts must factor in tax planning and timing of receipts to government, requiring judgement from model users.
- Compliance risk assessment:
  - Primarily backward-looking with granular project history needed (cost recovery statements, asset registers for depreciation, production volumes, realized prices, tax data).
  - More granular data than revenue forecasting to identify and quantify fiscal risks and inform policy changes to protect future revenue.
- Contract negotiations:
  - Data needs similar to fiscal regime analysis.
  - Investors often provide project models assuming full equity financing; governments must evaluate the impact of debt financing on government revenues — a key FARI feature — requiring detailed financing information.
  - Detailed analysis supports negotiators resisting concessions by demonstrating incentive impacts on project economics and revenues.
- Discount rate considerations:
  - Key parameter in model setup; debate exists on appropriate rate.
  - Governments often prefer a lower discount rate due to intergenerational considerations.
  - FARI simplifies by assuming investors and government share the same discount rate to allocate discounted project costs and benefits on a consistent basis, enabling judgments on distribution between parties.
  - This discount rate is also set consistently across countries to enable cross-country comparisons of key metrics for fiscal regime evaluation.

### III. Fiscal Regime Analysis for Policy Evaluation and Design

#### A. Tax Policy Objectives
- Fiscal regime as main tool for sharing risk and reward between investor and government.
- Common tax policy objectives and analytical measures:

  1) Capacity to generate revenues:
     - Objective: generate a “fair” share of revenues for government over project life.
     - Some governments prioritize early and stable revenues; others aim to maximize lifetime revenues.
     - Measurement:
       - Average Effective Tax Rate (AETR): share of project NPV captured by the fiscal regime.
       - Early revenue capacity assessed by measuring AETR at a higher discount rate or calculating minimum share of project earnings to government from start of production (e.g., effective royalty rate).
     - Policy note: A fiscal regime that includes progressive elements and minimizes regressive ones will maximize revenue collections.
     - Footnote on production sharing: minimum effective royalty from start of production can be calculated as: royalty rate + (1 – royalty rate) * (1 – cost recovery limit) * lowest share of government profit oil.

  2) Neutrality:
     - Objective: minimize economic distortions that could render marginal projects unviable or alter investor project rankings.
     - Measurement:
       - Compare post-tax breakeven price to pre-fiscal-regime breakeven price.
       - Calculate Marginal Effective Tax Rate (METR).

  3) Adaptability and progressivity:
     - Objective: ensure regimes handle volatile commodity prices and costs to reduce premature shutdowns or renegotiations.
     - Definitions:
       - Progressive regime: provides a stable or increasing share of project benefits to government (measured by discounted AETR) when investor returns exceed hurdle rate, while reducing burden when project is unprofitable.
       - First-best: constant marginal tax rate above a minimum return for investor (IMF 2018).
       - Second-best (common): governments may combine regressive mineral royalties with progressive instruments such as a resource rent tax (RRT) to balance early revenues with progressivity.

  4) Attractiveness to investors:
     - Objective: ensure sufficient attractiveness to encourage exploration and development.
     - Investor priorities:
       - Discounted after-tax value of the investment.
       - Payback period.
       - Breakeven price.
       - Stability of fiscal terms, given long horizons and large upfront investments.
     - Notes:
       - Fiscal stability assurances often sought in sectoral legislation or contracts (IMF (2008); Mansour and Nakhle (2016)).
       - Ease of administration matters; fiscal regimes must be administrable within existing capacity constraints. FARI does not include specific indicators for ease of administration.
- Policy trade-offs and common framework:
  - No single regime is ideal for all contexts.
  - For many countries, a combination of ad valorem royalty, CIT, and RRT is appealing:
    - Royalty: provides revenue whenever production is positive.
    - CIT: taxes normal return to equity as in other sectors.
    - RRT: targets economic rent.
  - Equivalent fiscal outcomes can be achieved via production sharing arrangements or hybrids.

*Italicized source attribution: Content extracted from wpiea2024089-print-pdf - REFERENCES (IMF Working Paper).*

### Box 1: Key Indicators Used in FARI Analysis – Investors

### Box 1: Key Indicators Used in FARI Analysis – Investors

### Investor-focused indicators
- Post-tax NPV
  - Definition: The post-tax NPV is the discounted present value of the total stream of net cash flows received by the investor over the life of the project.
  - Investor net cash flows: net cash flows are derived from gross revenues after deducting all project costs and all tax payments to the government:
    - 푁퐶퐹_t^푃표푠푡−푇푎푥퐼푛푣푒푠푡표푟 = 푃푟푒-푡푎푥푁퐶퐹_t − 푅표푦푎푙푡푦_t − 푇푎푥푒푠_t
  - NPV calculation (as in standard DCF analysis):
    - 푃표푠푡-푡푎푥 퐼푛푣푒푠푡표푟푁푃푉 = ∑_{t=0}^{n} [푁퐶퐹_t^{푃표푠푡−푡푎푥 퐼푛푣푒푠푡표푟} / (1+푟)^{푡}]
  - Variables: 푁퐶퐹_t^{푃표푠푡−푡푎푥 퐼푛푣푒푠푡표푟} is the investor net cash flows in year t, r is the discount rate, and n is the last year of the project.
  - Interpretation: Other things equal, an investor prefers projects with higher positive NPVs.

- Post-tax IRR
  - Definition: The IRR is the discount rate at which the NPV of the stream of cash flows is zero.
  - Application: The IRR here is the return on total funds (whatever the proportions of equity and debt). The model also calculates the return to equity by netting out the lender cash flow from the two equations above.

- Payback Period
  - Definition: In EI projects, the payback period occurs when the cumulative cash inflows from production are sufficient to recover the cumulative cash outflows incurred with exploration, development, operating costs and taxes.
  - Variants: The payback period can be calculated on undiscounted or discounted cash flows, and on leveraged and unleveraged funds.
  - Interpretation: Other things equal, an investor prefers a short payback period.

### Government-focused indicators (Box 1 Continued)
- Average Effective Tax Rate (AETR)
  - Definition: The AETR is the ratio of the NPV of government revenue (including royalty, income tax, resource rent tax, withholding taxes and so on, but excluding for instance taxes on the salaries of employees) to the NPV of the pre-tax net cash flows of a successful project, both calculated in discounted value.
  - Formula:
    - 퐴퐸푇푅 = NPV(퐺표푣 푅푒푣푒푛푢푒) / NPV(푅푒푣푒푛푢푒 − 퐸푥푝푙표푟푎푡푖표푛 − 퐷푒푣&푅푒푝푙푎푐푒푚푒푛푡퐶푎푝푒푥 − 푂푝푒푥 − 퐷푒푐표푚푚)
  - Interpretation: Indicates how much revenue a fiscal regime raises and is one definition of “government take.” The level of the AETR curve, not just its slope, is important: if the government’s share is so high that investors cannot recover their capital and a normal rate of return, investments will not take place.

- Marginal Effective Tax Rate (METR)
  - Definition: The METR is the wedge that the tax system drives between the minimum after-tax return that the investor requires, and the pre-tax project return needed to realize it.
  - Formula:
    - 푀퐸푇푅 = (푃푟푒-푇푎푥 퐼푅푅 − 푃표푠푡-푇푎푥 퐼푅푅) / 푃푟푒-푇푎푥 퐼푅푅
  - Interpretation: Reflects the burden placed by the fiscal regime on a project at the margin of viability (i.e., projects at the far end of a sector’s cost curve), indicating the extent to which the regime affects business investment decisions.
  - Modeling note: An important first step is to determine the price at which the post-tax investor return equals the hurdle rate (the breakeven price). The pre-tax return is then calculated assuming the project is executed with this price.

- Breakeven Price
  - Definition: The minimum price required to yield a specified post-tax return to capital over the full life of the project.
  - Modeling: Determined by the model through iterations and compared with the initial user price assumption.
  - Interpretation: A breakeven price above the user price implies that the project is economically unviable post-tax.

- Progressivity
  - Definition: Broadly defined as the ability of the fiscal regime to capture a larger share of profits in highly profitable projects, while reducing the tax burden in low profitability ones.
  - Analysis: The degree of progressivity can be analyzed by plotting the AETR over a range of pre-tax rates of return (obtained by varying assumed prices or unit costs in the model).

- Share of Total Benefits (STB)
  - Definition: An alternative to the AETR. “Total benefits” measures operating profits, without deducting the cost of capital investments, over the life of the project. It represents the amount of a project’s net revenues available to be shared between the government and investors.
  - Use: STB can be plotted at different levels of profitability to make visual comparisons of progressivity across fiscal regimes.

### Indicators as inputs for fiscal-instrument analysis
- With these indicators established, FARI is used to model and analyze fiscal instruments individually and in aggregate.
- The next modeling steps in the source proceed to introduce common features of tax/royalty concessionary regimes and production sharing arrangements, and then consider other fiscal instruments (state participation, carbon tax, and value added tax, VAT).

*IMF Working Paper — Box 1: Key Indicators Used in FARI Analysis – Investors*

### Box 2: Royalty Valuation Points

### Box 2: Royalty Valuation Points

### Valuation points and price reconciliation
- Stylized value chain shows valuation points A to F from extraction to final customer; value increases as product is beneficiated and transforms toward market requirements.
- Prices at different valuation points may be reconciled by adding/subtracting relevant costs (example: mine gate price to FOB export price by deducting local transport costs to the port).
- Reconciliation may be imperfect: processing changes reference prices and products have distinct market dynamics (inventories, capacity constraints, demand).
- Relative costs and value addition between mine, processing, transportation, and final market price vary significantly across minerals and between oil and gas.
- Source: IMF staff; model reference: FARI (published version recognizes one mineral product per project as a simplification).

### Structure of royalty rates and interaction with other fiscal instruments
- Ad valorem royalty design options:
  - Flat percentage rate (simpler collection and administration).
  - Variable rates by price, production levels (common for petroleum), or product type (e.g., lower rate commonly applied to natural gas).
- Tradeoffs:
  - Variable rates can introduce progressivity while retaining some simplicity.
  - Commodity price or production are imperfect proxies for profitability; progressive royalties remain distortionary.
  - Setting price thresholds to capture economic rents is challenging and requires monitoring and potential adjustment (for example, to account for inflation).
- Tax treatment interactions:
  - Royalties are an expense for the resource company and should be deductible when determining the tax base for CIT and other taxes; non-deductibility increases CIT liabilities and the project AETR.
  - Royalties are normally payable from the start of production when no taxable profits exist—tax rules should allow resulting tax losses to be carried forward.
  - In production sharing regimes, revenues shared are usually net of royalties; where a cost-recovery limit exists, it is important to determine whether the cost oil limit is calculated before or after royalties (more commonly after royalties).

### Numerical illustration of deductibility effects
- Example: Using the gold project,
  - Making a 5 percent royalty non-deductible results in higher CIT revenues and (assuming a 30 percent CIT rate) increases the discounted AETR by 3 percentage points (royalty revenues remain unchanged).
  - To obtain equivalent revenues with a deductible royalty, the royalty rate would need to be increased to 7 percent.
- Implication: Numerical equivalency exists between royalty rate and deductibility, but composition affects progressivity of the overall regime.

### Royalty specification in the FARI model
- Options included:
  - Flat royalty: same rate regardless of other variables.
  - Price-based royalty: allows two different rates above and below a price threshold; price thresholds can be defined with or without inflation indexing.
- Economic characteristics:
  - Government’s share under a flat royalty does not vary with prices, production, or costs—royalties are regressive in isolation: as project profitability rises, the AETR falls.
  - Deductibility of transport costs from the royalty base makes the royalty slightly less regressive.
  - Price-based variable rates can introduce progressivity but are imperfect measures of profitability, set arbitrarily, may be overtaken by market events, ignore cost-structure differences, and may increase cut-off grade reducing mineable resources.
  - Applying a variable rate to full mineral value creates a “cliff” effect (abrupt rate changes with small price variations); applying variable rates only to incremental value above a price threshold smooths the effective royalty rate.

### Corporate Income Tax (CIT) — determination and modeling considerations
- CIT common for mining and petroleum with varied country treatments (modified rates, accelerated depreciation, longer loss-carry forward).
- Notional calculations differ from pure cash flows (e.g., depreciation timing wedge between cash event and CIT deduction affects discounted analysis).
- Tax base components: exploration costs, royalties, operating costs, interest payments (subject to limits), depreciation allowances.
- Ring-fencing:
  - Limits consolidation of income and expenses across projects or corporate activities.
  - FARI assumes ring-fence applies at the license or contract area.
- Depreciation in FARI:
  - Five cost categories; three capitalized: exploration, development, replacement capital costs.
  - Single straight-line depreciation calculation; straight-line rate chosen to approximate country asset types including, where applicable, accelerated allowances.
  - Exploration costs can be capitalized and depreciated (timing options) or expensed.
- Timing effects:
  - Shorter depreciation period allows earlier recovery of investment and lower initial CIT payments; in undiscounted terms sum of CIT over time and AETR unchanged, but discounting makes faster expensing more attractive to investors.
- Loss carry-forward:
  - Longer or indefinite carry-forward may be appropriate; some countries limit amount deductible per period.
  - Interaction with depreciation method matters (faster depreciation without longer carry-forward may cause loss expiry and higher CIT payments).
  - Published FARI assumes indefinite loss carryforward (does not model loss limitation rules).
- Decommissioning and abandonment:
  - Governments commonly require investors to set aside funds in advance; tax legislation usually allows deductions for decommissioning expenses or contributions while project generates income; final reconciliation and rules for surplus/deficit treatment are required.
- Debt financing and interest deductibility:
  - Common safeguards: limits on interest deductibility via debt-equity ratio limits or earnings-stripping rules (e.g., ratio to EBITDA).
  - FARI includes debt financing calculations with general assumption debt is provided by the parent company to evaluate parent-company outcomes reflecting interest-deduction benefits.
- Withholding taxes:
  - Collected on payments to non-residents; safeguard against profit shifting but can be mitigated by routing through treaty countries.
  - Withholding tax on dividends is economically equivalent to free government participation in an incorporated JV.
  - For modeling: prospective projects may use lowest treaty rate; existing projects use actual rates if available; FARI simplifies by assuming a deduction for withholding taxes unless more detail is justified.
- CIT rates for EI:
  - Statutory CIT generally applied; some countries use higher, variable, or lower rates or tax holidays.
  - Reduced CIT rates are of questionable justification given resource rents and limited effect on viability; higher rates may invite tax planning to move income outside ring-fence.
  - Note: Global Anti-Base Erosion Model Rules (Pillar Two) will weaken the case for reduced CIT rates to attract investment.

### Economic analysis of CIT interaction with royalties
- CIT generally stable across outcomes and trends toward the CIT rate.
- At very low profitability, CIT becomes regressive (costs expire as tax losses), but typically less regressive than royalty alone.
- Combined royalty and CIT ensure a minimum take at low profitability and at start of production, while at high profitability government take is more stable than with fixed-rate royalty alone.

### Resource Rent Taxes (RRT) and pure rent taxes
- Pure rent (Brown) tax: applies to positive cash flows; negative cash flows refunded to investor—rare in practice; economically equivalent to government participation via fully paid equity.
- Cashflow RRT:
  - Negative cashflows carried forward with an “uplift” often set equivalent to investor’s minimum required return.
  - No deduction for financing costs; immediate expensing of capital costs provides time value benefit.
  - Simplification benefits: no tax depreciation calculations or interest deductions, limiting profit shifting opportunities.
- Interaction with CIT:
  - Choice of applying RRT pre- or post-CIT matters; if post-CIT, hurdle rate should be lower than if applied pre-CIT.
  - Tradeoff: post-tax RRT can act as backstop against CIT leakage but increases administrative complexity.
- Design challenges:
  - Correct choice of imputed rate of return (hurdle rate) critical: too high => tax never applies; too low => taxes normal return and distorts investment.
  - In practice RRT rates are set below rates that would capture all economic rents (unobservable costs may imply actual rents lower than observed).
  - Single rate simpler administratively; multi-tier rate allows more progressivity.
- Reference discussions: IMF (2010), IMF (2018), Australian Government (2016).

### Production Sharing Regimes (PSCs)
- Investors incur project costs; investors and government share cashflow-based profits (before or after royalties depending on arrangement); investors receive cost recovery share.
- Determination of profit petroleum:
  - Profit petroleum = net revenue after royalties minus cost petroleum (cost oil/cost gas).
  - Cost recovery analogous to CIT deductions but often with immediate expensing for capital and aggregate cost recovery limit (percentage of production after royalties).
  - Cost recovery limit ensures government receives a share from production start when project not yet profitable; combination of royalty, cost recovery limit, and government share of profit petroleum operates like a minimum effective royalty.
  - PSCs typically do not allow interest deductions.
- Structures to set profit petroleum sharing rates:
  - Fixed-rate or variable (progressive) systems using proxies:
    - DROP (daily rate of production): government share increases with average DROP; simple and verifiable; incomplete measure of profitability since it ignores price and cost changes.
    - R-factor: government share based on ratio of cumulative revenues to cumulative costs (models vary: revenues/costs or operating profits/initial investment). R = 1 when nominal investment cost recovered. Below R<1 minimum government share applies; above, tiered or interpolated progressive sharing applies. Sliding scale interpolation avoids tier “jumps.”
    - ROR (rate of return): government share set relative to cumulative IRR from exploration start to sharing date; accounts for time value via uplift to negative cashflows; akin to RRT when exploration included; usually a minimum share applies below the first IRR threshold.
- Pay-on-behalf (POB) systems:
  - Contractor subject to CIT on share of profit oil; government can be indifferent between pre-tax and post-tax (POB) sharing if compensating share, no CIT leakage, and quick budget flows.
  - POB advantages:
    1) Single verification/audit of revenues and costs.
    2) Fiscal terms stable irrespective of CIT rate changes.
    3) Automatic ring-fencing by contract area.
  - Considerations: requires clear agency roles, tax authority participation in profit oil audits, and choice of recipient of CIT payments affects budget implications.
- Economic analysis:
  - Production sharing can be progressive; progressivity degree depends on sharing mechanism and key parameters.
  - Cost limit adds regressive element similar to royalty.
  - Multiple-tier RRT regimes can emulate R-factor profiles; differences often reflect parameter choices more than inherent differences between approaches.

### State participation — forms, financing, and economic implications
- State participation options:
  - Working interest: State contributes share of all project costs as incurred; aligns state risks/rewards with investors; conceptually akin to a pure rent tax (Brown tax); most progressive and highest reward to state if financed from cash assets.
  - Carried interest: State’s share of development spending is financed (carried) by others; repayments with interest from state’s share of production after production starts; avoids upfront budget burden; carry can be equivalent to RRT where RRT rate equals equity share and uplift equals carry interest rate.
  - Free equity: State receives equity stake without contributing costs; behaves like dividend withholding tax—revenue only when dividends paid; most regressive and rarely truly “free” (other fiscal instruments often adjusted).
- Key financing dimensions for carries:
  - Quantum to be carried.
  - “Price” of the loan (interest rate).
  - Repayment pattern (priority for quick repayment versus earlier revenue generation).
- Entity and tax treatment:
  - Incorporated JV: taxed as separate entity; after-tax profits distributed as dividends.
  - Unincorporated JV: partners taxed separately on their share of project cashflows.
  - FARI configurations: mining model assumes incorporated JV; petroleum model treats JV partners taxed separately (private investors treated as single shareholder and NOC as another); NOC allocated share of net cash flows with carry arrangements modeled; no further taxes on NOC unless country context requires.
- Effects on investment and revenues:
  - Level of debt financing by majority investor affects government revenues (more debt lowers after-tax JV distributions).
  - Carried interest loans typically charge interest above investor’s cost—higher rate increases repayment time.
  - Carried interest repayment terms influence equivalence to RRT and timing/profile of revenue.
- Economic analysis:
  - State participation terms affect timing/profile of government revenue, progressivity, and incentives for marginal projects.
  - Free equity: no upfront capital but most regressive.
  - Working interest: requires capital, shares risk, yields highest reward and most progressive.
  - Carried interest: no initial capital from state, but rewards reduced by financing costs; state shares risk only if loan has recourse or state guarantees.
  - FARI assumption: state contributes working interest from existing cash assets; if state must borrow, financing terms alter relative returns.

### Carbon tax — design, bases, and economic effects
- Rationale: Producing and burning fossil fuels impose societal costs via GHG emissions, local air pollution; carbon pricing internalizes these costs.
- Carbon pricing design choices: base, rate, interaction with other fiscal instruments.
- Emissions scope definitions:
  - Scope 1: direct emissions from extraction, on-site transport, power generation, processing.
  - Scope 2: emissions from purchased electricity generation (should be taxed at generation point).
  - Scope 3: emissions after fuel leaves ring-fence including combustion (generally taxed in consuming country).
- FARI implementation:
  - Unit: grams of carbon dioxide equivalent (CO2 eq) per megajoule (MJ).
  - FARI includes carbon tax on Scope 1 emissions in the petroleum model only (Scope 1 and 2 emissions-intensities vary; published estimates range from 3 to 30 g CO2 eq/MJ by country).
  - Example equivalence: 16 g CO2 eq/MJ equates to 0.1 tonne per barrel of oil equivalent; a USD 50 per tonne carbon tax on Scope 1 emissions-intensity of 16 g CO2 eq/MJ results in a tax of USD 5 per barrel of oil.
- Emissions-intensity and mitigation:
  - Scope 1 taxes incentivize reducing emissions-intensity (e.g., capture methane rather than venting, leak detection/repair, electrifying operations).
  - Switching venting to flaring reduces total GHG warming (flaring converts methane to CO2; a tonne of flared methane releases about three tonnes of CO2, ~90 percent reduction in global warming relative to vented methane over 100 years).
- IMF guidance:
  - Remove fossil fuel subsidies and impose carbon tax on Scope 1 emissions so producers internalize extraction-related societal costs.
  - Scope 2 tax applied at power generation; Scope 3 taxes generally in consuming country (outside published FARI).
- Tax rate approaches:
  - Phase in tax with progressive increases over time.
  - Target level consistent with global temperature objectives (reference: Stern and Stiglitz, 2017: USD 40 to 80 in 2020 and USD 50-100 by 2030).
  - Increase tax for production near populated areas to include local health costs of methane and particulates (see IMF (2021c) for country-specific optimal levels).
- FARI rate mechanics:
  - Carbon tax can be fixed in nominal or real terms; variable via linear increase to target year or fixed percentage increase per year.
- Deductibility and cost recovery:
  - Decision on deductibility/cost recovery affects investment distortion; general view that taxes on negative externalities should be deductible and recoverable like labor and capital costs.
  - A lower non-deductible carbon tax could be calibrated to match effects of a higher deductible carbon tax.
- Economic impacts (stylized oil project example):
  - Imposing a USD 75 per tonne carbon tax:
    - Low emissions project (emissions-intensity = 3 g CO2 eq/MJ): investor IRR falls by 1 to 2 percentage points relative to no tax.
    - High emissions project (emissions-intensity = 30 g CO2 eq/MJ): investor IRR falls to 7 percent (19 percentage points lower) when carbon tax is not deductible or cost-recoverable; demonstrates significant incentive to reduce emissions-intensity.
  - Carbon tax can cause earlier cessation of production (reach economic limit sooner) by increasing marginal production costs:
    - In the example, production stops five years earlier for high-emissions project when tax not deductible and recoverable, and one year earlier when tax is recoverable and deductible.
    - For low emissions project, economic limit not impacted by carbon tax in the example.
- Additional context:
  - Novel research shows higher-than-expected methane emissions; sector emits 33 percent of human-caused methane (IEA, 2021a).
  - Low-cost abatement potential: 50 to 75+ percent of fossil fuel production-based emissions avoided at carbon price of USD 50 per tonne CO2 eq (IEA, 2021a; McKinsey, 2019).
  - CO2 eq: methane GWP of 72 over 20-year horizon (IPCC, 2007).
- Modeling note: FARI does not automatically include behavioral responses to the carbon price.

*Source: IMF staff (Box 2: Royalty Valuation Points, from the IMF Working Paper "Cash Flow Analysis of Fiscal Regimes for Extractive Industries").*

### Box 3: The Impact of the Energy Transition on Fiscal Regime Design

### Box 3: The Impact of the Energy Transition on Fiscal Regime Design

### Energy transition implications for fiscal regime design
- Hydrocarbon and coal demand, investment, and prices are expected to fall (IEA, 2021b) as the energy transition progresses, leading to more competition for upstream investment and lower economic rents.
- Policymaker trade-off:
  - Attract new investment by rebalancing from distortive to progressive fiscal mechanisms (e.g., reducing royalties and increasing profit-based taxes).
  - Maximize benefits from existing projects by maintaining (or introducing) production-based taxes.
- Key trade-offs and risks:
  - Reducing royalties and increasing profit-based taxes may incentivize investment but can reduce government revenue because economic rents are less likely to materialize and profit-based taxes are more difficult to administer.
  - Maintaining or introducing production-based taxes could increase revenue from existing projects but risks earlier decommissioning and reduces attractiveness for new investment.
- Non-fiscal considerations:
  - Position on the cost curve matters: low-cost producers are more likely to attract continued investment regardless of fiscal regime design.
  - Presence of state-owned companies may introduce additional considerations in design and negotiation timelines.

### Mineral demand from the transition and fiscal implications
- Demand effects for minerals used in transition technologies (e.g., EV batteries, magnets for wind turbines and EV motors) include a significant expansion in mining of:
  - rare earth elements, copper, nickel, lithium, cobalt, and manganese.
- Fiscal and geological policy implications:
  - Importance of fiscal settings (and geological data) that encourage exploration and timely development of economically viable resources.
  - Countries endowed with these minerals could experience windfall gains, but pressure to bring production online quickly risks rushing fiscal negotiations.

### Value Added Tax (VAT) — modeling in FARI and economic effects
- VAT fundamentals and extractive industries (EI):
  - VAT is largely borne by domestic consumers; a properly designed and implemented VAT should not affect investment decisions.
  - Businesses generally pay VAT on inputs, charge VAT on outputs, and remit excess output VAT to government; exports are not charged VAT and governments refund input VAT credits that exceed output VAT.
- Risks when VAT does not function as intended in EI:
  - Long EI development phases require a properly functioning refund mechanism to avoid unintended costs.
  - Extractive companies accumulate refund credits during development because they pay VAT on inputs without generating outputs; projects with large export shares face similar net credit positions if input VAT is not refunded timely.
  - Delayed refunds increase project costs and can distort investment decisions by reducing investor IRR, with larger impacts for more capital-intensive projects.
  - Governments struggling to pay timely refunds may provide special VAT schemes (e.g., zero-rating or exempting company inputs), which can cause problems elsewhere in the VAT system and among suppliers.
- Four important assumptions for modeling VAT in FARI:
  1. All production is assumed to be exported, meaning the investor does not charge any output VAT and requires refunds on all input VAT.
  2. The cost of VAT exemptions is fully borne by suppliers, unless project costs are inflated to reflect a passthrough to the investor.
  3. Input VAT paid before the investor is registered for VAT is not captured (though in reality it may stick to input costs, be eligible for a refund upon registration, or be borne by the supplier).
  4. Some VAT schemes are not included in the model, such as offsets against other tax liabilities.
- Economic analysis summary:
  - VAT does not impact government take or investor profitability when refunds are paid immediately.
  - Investor IRR declines as refund delay lengthens; reductions in investor profitability illustrate that VAT refund delays can deter investment.
  - Governments can improve the fiscal regime’s competitiveness through ensuring prompt refunds.
  - Note: Where country policy is to refund VAT to taxpayers, VAT revenue received may be better excluded from estimates of total revenue from the fiscal regime, since it generates a corresponding refund liability.

### Comparing overall fiscal regimes (illustrative mining example)
- Project example parameters:
  - Gold project used in the mining model with a pre-tax IRR of 28 percent and a project NPV of nearly US$ 600 million.
- Summary of four illustrative fiscal regimes (main parameters):
  - Regime 1: Royalty + CIT
    - Royalty rate (net, deductible): 7 percent
    - CIT rate (straight-line depreciation over 5 years): 25 percent
    - RRT rate (20 percent uplift on negative cashflows): -
    - State participation percentage (free equity): -
  - Regime 2: High royalty / low CIT
    - Royalty rate (net, deductible): 9 percent
    - CIT rate (straight-line depreciation over 5 years): 21 percent
    - RRT rate (20 percent uplift on negative cashflows): -
    - State participation percentage (free equity): -
  - Regime 3: Low royalty + high CIT /+ RRT
    - Royalty rate (net, deductible): 2 percent
    - CIT rate (straight-line depreciation over 5 years): 26 percent
    - RRT rate (20 percent uplift on negative cashflows): 20 percent
    - State participation percentage (free equity): -
  - Regime 4: Royalty + CIT + SP
    - Royalty rate (net, deductible): 5 percent
    - CIT rate (straight-line depreciation over 5 years): 20 percent
    - RRT rate (20 percent uplift on negative cashflows): -
    - State participation percentage (free equity): 10 percent
- Key comparative findings:
  - At a gold price of US$ 1500 per ounce, the AETR NPV is 40 percent for all four regimes.
  - Despite equal AETR NPV at the base case, regimes differ in risk/reward sharing and timing of revenues:
    - Regimes 1 and 2 rely only on royalty and CIT revenue streams.
    - Regimes 3 and 4 include additional revenue streams: RRT in Regime 3 and state participation in Regime 4.
    - Regime 2 (heavy reliance on production-based royalty) generates frontloaded revenue; Regime 3 (modest royalty plus RRT) backloads revenue.
  - Timing and profile specifics:
    - All four regimes start generating revenues from the first year of production (2025).
    - The high royalty regime (Regime 2) generates 5 times higher revenue in year four of production than Regime 3 (low royalty with RRT).
    - From the seventh year of production onwards, Regime 3 generates the highest revenue until production ends.
    - Regime 1 (higher CIT) and Regime 4 (lower CIT combined with free equity) have nearly identical revenue profiles, noting that state participation income assumes full dividend distribution by the government entity holding the equity stake.
- Progressivity and breakeven analysis:
  - Progressivity:
    - Regime 2 (heaviest reliance on royalty) is the most regressive; royalty tax base (value of minerals sold) does not consider profitability, so at lower commodity prices the royalty takes an increasing share of project cash flows.
    - Regime 3 (modest royalty and RRT) produces a relatively flat progressivity curve across a wide range of outcomes, including a pre-tax IRR of only 15 percent.
  - Breakeven prices to achieve a 10 percent after tax IRR in real terms and associated observations:
    - Regime 2 breakeven price: US$ 1032 per ounce (impacts marginal projects most negatively).
    - Regime 1 breakeven price: US$ 1,004 per ounce.
    - Regime 4 breakeven price: US$ 1,017 per ounce.
    - Regime 3 breakeven price: US$ 968 per ounce (lowest breakeven).

### Modeling, capacity, and looking ahead
- Comparative analysis caveats:
  - Focus on relative rankings and how regimes handle volatility and uncertainty rather than absolute AETR levels.
  - Differences in overall AETR levels should be considered in country context: maturity of basin (petroleum), infrastructure quality, certainty of license tenure, fiscal stability mechanisms, and how these factors affect investor risk premia.
  - Qualitative considerations may be more influential on investors than fine fiscal regime details.
- Model quality and use:
  - Quality of fiscal regime analysis depends on the tool (such as FARI), assumptions, data, and model-user judgments; these must be transparently accounted for.
  - For capacity-constrained governments in developing countries, short-term priority may be skills to interrogate models built by others to identify misleading results, errors, and overly-optimistic assumptions quickly.
- IMF plans and technological outlook:
  - IMF continues to invest in improving the FARI model and training country officials on its use, including to incorporate GHG considerations.
  - Emerging technologies (e.g., generative artificial intelligence) may reshape fiscal modeling by speeding mechanical model creation or providing AI-generated evaluations of resource projects and fiscal regime options.
  - Core rule: decision makers should remain skeptical of black-box results and ensure underlying user preferences, judgments, and biases are examined and addressed.

*Source: Box 3, "The Impact of the Energy Transition on Fiscal Regime Design", IMF Working Paper — Cash Flow Analysis of Fiscal Regimes for Extractive Industries.*

### Annex I. Practical Guidance

### Annex I. Practical Guidance

### A. Adding a New Fiscal Regime
- Definition: A fiscal regime is a set of tax and non-tax mechanisms that a host country uses to raise government revenue from a natural resource project.
- Location of user inputs:
  - Fiscal regime user inputs are in yellow-colored cells, located towards the top of the “FiscalModel” sheet (to the right of column J, black outline).
  - Each input column contains a single fiscal regime, with the regime name in row 11 and fiscal terms below.
- Pre-loaded regimes and capacity:
  - The model is pre-loaded with several illustrative fiscal regimes.
  - FARI can store inputs for up to 40 regimes at once but only performs calculations for the fiscal regime selected in cell C6 of “Dashboard”.
- Mechanics:
  - Using an index-match formula, the terms of the selected fiscal regime are reflected in column F of “FiscalModel” (red outline) and this column F is referenced in downstream fiscal calculations.
  - Important user guidance: enter fiscal regime inputs in the yellow cells and maintain formulas in column F; entering inputs directly in column F will cause model errors.
- Steps to add a new regime:
  - Enter desired values into an empty fiscal regime input column (example given: column O).
  - Use a descriptive regime name (displayed in analytical routines and charts).
  - Ensure the “Dashboard” shows the new regime by entering the new regime name in cell C6 of “Dashboard” (or selecting it from the drop-down).
  - Add the new regime name in one of the yellow-colored cells of the top data table on “Dashboard” to include it in analytical routines.
  - Update data tables by pressing the F9 key; update breakeven price analysis via the “Breakeven” button in the relevant “Dashboard” section.
- Sources for fiscal regime information (examples listed):
  - Resource contracts
  - Government websites (Ministry of Finance, regulatory agencies)
  - IMF publications
  - Regulatory filings (e.g., London Stock Exchange, US SEC, Canada NI 43-101, Australian JORC)
  - Ernst and Young Global Oil and Gas Tax Guide (note: not updated since 2019)
  - Consultancy summaries (E&Y, PWC, Deloitte, KPMG, Lexology)
  - Company websites (investor presentations, contract disclosures)

### B. Adding a New Project
- Required project data:
  - Production: petroleum model — daily rate (thousands of barrels of oil per day); mining model — annual volumes (thousands of a mineral’s relevant unit).
  - Costs: entered in millions of US dollars in real terms of the first model year (costs should not include the impact of inflation).
- Cost disaggregation:
  - Costs are disaggregated into six categories to reflect different fiscal treatments and project stages (exploration, development, production, decommissioning).
  - Transport (and refining) costs post-fiscal point correspond with costs incurred outside the fiscal ring-fence; other costs are incurred within the fiscal ring-fence.
- Procedure to add a project:
  - Copy an existing project worksheet (example sheets: “800MMbbl_A” or “Gold(2MMoz)”) via “Move or Copy...” → “Create a copy”.
  - Rename the new sheet with a descriptive title and update project data assumptions.
  - Specify the mineral produced in the mining model by linking the relevant project-data cell to the desired variable in “Translate”.
  - Add the sheet name to the project section of “Inputs”, then select the project in cell C7 of “Dashboard”.
  - Do not add any rows above the decommissioning costs row in the project data sheets (doing so will cause the model to malfunction).
  - If the mineral was not previously included in the model, update the price in the “Dashboard”.
- Model guidance:
  - Pre-loaded projects and fiscal regimes are illustrative and not intended to represent a specific project or country regime.
  - Pre-loaded projects result in reasonable before-tax profitability; project costs and production structures vary significantly and must be adapted to country context.
  - The dashboard contains sensitivity inputs to vary cost and production levels directly below commodity price inputs.

### C. Key Assumptions
- Role: FARI requires inputs for economic and financing assumptions in addition to fiscal regime and project data.
- Commodity price (Dash board):
  - If available, use the long-term expected international benchmark price in real terms of the first modelled year.
  - Alternatives: current price, average of past several years, or a futures price.
  - Suggested data sources: LME, IMF, IEA, Fastmarkets.
  - Model note: the price received by the project is calculated by deducting per-unit transport (and processing) costs post-fiscal point from the international price inputted in the project data.
- Inflation (Inputs):
  - Used to convert project costs and commodity prices to nominal terms for fiscal calculations and to re-convert results back to real terms for indicators and discounting.
  - Input should reflect the long-term Consumer Price Index for US dollars.
  - Suggested source: US Federal Reserve.
- LIBOR (real terms) (Inputs):
  - LIBOR was a benchmark interest rate until 2023 and is referred to in the 2021 models.
  - As LIBOR is phased out, an alternative short-term benchmark (e.g., SOFR) may be used.
  - A margin above the benchmark is assumed for carried state participation financing costs; the benchmark rate alone is used for decommissioning provisions.
  - Data sources: LIBOR (historic) (ICE) and SOFR (US Federal Reserve).
- Discount rate (Inputs):
  - Key indicators are calculated as net present values using a discount rate entered in real terms.
  - Conversion: nominal to real via formula (1 + nominal discount rate) / (1 + inflation rate).
  - Discount rates vary by country and between government and investor; the public model assumes a single discount rate for analysis.
  - Suggested sources: NYU dataset for private investors, IMF for government borrowing rates.
- Hurdle rate (Dash board):
  - Used to determine the breakeven commodity price; it is the minimum return a company requires to undertake an investment and is usually higher than the discount rate.
  - Company-specific and often confidential; OIES 2019 provides a summary.
- Proportion of development costs borrowed (FiscalModel):
  - Percentage of development costs funded using debt; debt financing available as long as project cash flows after indirect taxes and royalties remain negative.
  - Public FARI model configuration: debt is assumed provided by the parent company to its local subsidiary (and the state participant, if relevant), so the parent is the provider of all funding.
  - This enables evaluation of parent company cashflows including benefit of debt financing; discount rate derived from weighted average cost of capital.
  - Typical assumption: proportion of debt generally assumed to be around 70 percent, reflecting experience from country work and host-country maximum debt-to-equity ratios.
  - The dashboard presents results for investor (parent company) and lender combined, as well as investor alone; breakeven prices are calculated for the aggregated parent company including the share of debt.
- Repayment period (FiscalModel):
  - Number of years in which the loan will be repaid, assumed to start the year after debt financing ends.
  - It will vary by project and could range from roughly five to fifteen years.
- Loan interest rate (FiscalModel):
  - The interest rate for the loan in nominal terms; project specific and should be at least a few percentage points higher than the benchmark interest rate in nominal terms to reflect project and country risk premium.
- Data availability notes:
  - For several financing variables (proportion borrowed, repayment period, loan interest rate), the annex notes “None available” for specific public data sources.

### D. How to Add Fiscal Instruments and Customize the Model
- Rationale: The published model includes simplifications. To capture a country’s exact fiscal terms, users may need to add or adjust fiscal mechanisms (e.g., depreciation methods, new deductions, new cost-recoverable items).
- Prerequisite: Users should have relatively advanced Excel knowledge.
- Steps to add a new fiscal mechanism:
  1. Add inputs:
     - Insert new rows above the lower grey row titled “bottom of fiscal regime parameters” in the inputs section of “FiscalModel”.
     - Inputs include any rates and parameters to determine the tax base (example: depreciation rates).
     - Input columns are color-coded yellow; column F contains the index-match formula and must be preserved.
  2. Add fiscal calculations:
     - Implement calculations reflecting the specifics of the new mechanism in the relevant section of “FiscalModel”. All fiscal calculations are located between the fiscal regime inputs and government revenue consolidation.
     - The location depends on mechanism type: taxes applying to costs or production occur towards the top of fiscal calculations because they are often deductible for income and rent-targeting taxes and may be cost recoverable under production sharing.
     - Calculations must reference fiscal parameters in column F (not the input columns).
     - Include reconciliation checks to protect against errors.
  3. Link the mechanism across the model:
     - If tax deductible, include it as a tax deduction in the CIT section.
     - Add the revenue from the new mechanism to the list of revenue sources at the start of results in “FiscalModel”.
     - Link any added reconciliation to the full list of reconciliation checks at the bottom of “FiscalModel”.
     - Add the calculated revenue to the “Charts” and “Dashboard”.
- General guidance: Ensure consistency with existing formula structure and reconciliation checks to avoid model errors.

*Source: Annex I. Practical Guidance, FARI petroleum model (FiscalModel, Dashboard, Translate) — IMF Working Paper materials.*

### Annex II. Documentation of Modeling Assumptions

### Annex II. Documentation of Modeling Assumptions

### A. Project economics in baseline
- Modelled projects:
  - Petroleum: Project 800MMbbl_A
    - Production: 800 million barrels
    - Production years: 27 years
    - Project unit costs US$ (2021): 38.5/barrel
    - Pre-tax IRR (real): 32 percent
    - Pre-tax NPV US$: 9,994 million
  - Mining (Gold): Project Gold (2MMoz)
    - Production: 2,000, ounces
    - Production years: 17 years
    - Project unit costs US$ (2021): 723/ounce
    - Pre-tax IRR (real): 28 percent
    - Pre-tax NPV US$: 505 million
  - Mining (Iron Ore): Project IronOre (250MMt)
    - Production: 250,000,000 metric tonnes
    - Production years: 21 years
    - Project unit costs US$ (2021): 43/dry metric tonne
    - Pre-tax IRR (real): 14 percent
    - Pre-tax NPV US$: 1,113 million
  - Mining (Coal): Project Coal (250MMt)
    - Production: 250,000,000 metric tonnes
    - Production years: 28 years
    - Project unit costs US$ (2021): 39/ metric tonne
    - Pre-tax IRR (real): 22 percent
    - Pre-tax NPV US$: 1,105 million

### B. General assumptions
- Commodity price in baseline scenario:
  - Oil US$ 55/barrel
  - Gold US$ 1500/ounce
  - Iron US$ 80/dry metric tonne
  - Coal US$ 90/metric tonne
- Discount rate in real terms: 8 percent
- Inflation rate: 2 percent
- Real LIBOR (benchmark interest rate): 0 percent
- Decommissioning:
  - Petroleum: Fund with provisioning starting at 50 percent of depletion
  - Mining: Fund with provisioning starting at 60 percent of depletion
- Debt financing:
  - Petroleum: 70 percent of negative cashflows during the development period financed by a loan provided by the parent company. The loan carries an interest rate of 3 percent over the nominal benchmark interest rate and is repaid over 10 years.
  - Mining: 70 percent of negative cashflows during the development period financed by a loan provided by the parent company. The loan carries an interest rate of 5 percent over the nominal benchmark interest rate and is repaid over 5 years.

### C. Fiscal regime assumptions
- Note: Other fiscal instruments available in FARI but not listed below have not been applied in the scenarios used for this paper.

- Petroleum fiscal regimes (selected features preserved verbatim):
  - Royalty
    - 8 percent, net base
    - Carbon Tax: (blank)
    - VAT: (blank)
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 5 years from start of production
    - RRT: 40 percent above hurdle rate of 15 percent with CIT deductible
    - Production Sharing: (blank)
  - DROP PSC
    - Royalty: 8 percent, net base
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 5 years from start of production
    - Cost recovery limit: 80 percent
    - Profit oil sharing following DROP:
      - Tier 1: 20 percent DROP <= 20 kbopd
      - Tier 2: 30 percent DROP > 20 and <=70 kbopd
      - Tier 3: 40 percent DROP > 70 and <=120 kbopd
      - Tier 4: 50 percent DROP > 120 and <=170 kbopd
      - Tier 5: 60 percent DROP > 170 kbopd
    - R-factor PSC features also noted in other regimes
  - R-factor PSC
    - Royalty: 6 percent, net base
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 5 years from start of production
    - Cost recovery limit: 80 percent
    - Profit oil sharing following R-Factor:
      - Tier 1: 20 percent R-Factor <= 1
      - Tier 2: 30 percent R-Factor > 1 and <=2 kbopd
      - Tier 3: 40 percent R-Factor > 2 and <=3 kbopd
      - Tier 4: 50 percent R-Factor > 3 and <=4 kbopd
      - Tier 5: 60 percent R-Factor > 4 kbopd
  - R-factor PSC; carbon tax deductible
    - Royalty: 6 percent, net base
    - Carbon Tax: US$ (2021) 75/tonne of CO2 eq (real), recoverable for production sharing and deductible for CIT
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 5 years from start of production
    - Cost recovery limit: 80 percent
    - Profit oil sharing following R-Factor: same tiered structure as R-factor PSC above
  - R-factor PSC; carbon tax not deductible
    - Royalty: 6 percent, net base
    - Carbon Tax: US$ (2021) 75/tonne of CO2 eq (real), not recoverable for production sharing and not deductible for CIT
    - CIT and profit oil sharing: as above
  - R-factor PSC; refund immediate
    - Royalty: 6 percent, net base
    - VAT: 20 percent, 80 percent of CAPEX and 20 percent of OPEX subject to VAT, applicable from exploration, refund immediate
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 5 years from start of production
    - Cost recovery limit: 80 percent
    - Profit oil sharing following R-Factor: tiered structure as above
  - R-factor PSC; refund 2 years delay
    - Royalty: 6 percent, net base
    - VAT: 20 percent, 80 percent of CAPEX and 20 percent of OPEX subject to VAT, applicable from exploration, refund 2 years delayed
    - CIT and profit oil sharing: as above
  - R-factor PSC; refund 4 years delay
    - Royalty: 6 percent, net base
    - VAT: 20 percent, 80 percent of CAPEX and 20 percent of OPEX subject to VAT, applicable from exploration, refund 4 years delayed
    - CIT and profit oil sharing: as above
  - R-factor PSC; no refund
    - Royalty: 6 percent, net base
    - VAT: 20 percent, 80 percent of CAPEX and 20 percent of OPEX subject to VAT, applicable from exploration, no refund
    - CIT and profit oil sharing: as above

- Mining fiscal regimes (selected features preserved verbatim):
  - Royalty (gross, deductible) + CIT
    - Royalty: 5 percent, gross base, CIT deductible
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 5 years from start of production
    - RRT: (blank)
    - State participation: (blank)
  - Royalty (gross, non-deductible) + CIT
    - Royalty: 5 percent, gross base, not CIT deductible
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 5 years from start of production
  - Higher royalty (gross, deductible) + CIT
    - Royalty: 7 percent, gross base, CIT deductible
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 5 years from start of production
  - Royalty (gross)
    - Royalty: 5 percent, gross base
  - Royalty (net)
    - Royalty: 5 percent, net base
  - Price Royalty (gross)
    - Royalty: 5 percent below US$ 100/dry metric tonne, 10 percent above US$ 100/dry metric tonne, gross base
  - Price Royalty (gross, indexed)
    - Royalty: 5 percent below US$ (2021) 100/dry metric tonne, 10 percent above US$ (2021) 100/dry metric tonne, gross base
  - CIT only (immediate)
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 1 years from start of production
  - CIT only (3 years)
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 3 years from start of production
  - CIT only (5 years)
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 7 years from start of production
  - Royalty (net) + CIT
    - Royalty: 5 percent, net base
    - CIT: 30 percent, exploration costs expensed, development costs depreciated over 5 years from start of production
  - Low royalty + low CIT /+ RRT
    - Royalty: 5 percent, net base, CIT deductible
    - CIT: 20 percent, exploration costs expensed, development costs depreciated over 5 years from start of production
    - RRT: 20 percent above hurdle rate of 20percent with CIT deductible
  - State participation and carry/interest constructs:
    - FE-10: 10 percent free equity
    - CI-10: 10 percent carried interest, carry repaid out of 100% of state participation cashflows, carry loan available until 10th year of production at % percent over the nominal benchmark interest rate.
    - WI-10: 10 percent working interest

*Cash Flow Analysis of Fiscal Regimes for Extractive Industries, Working Paper No. WP/2024/089*

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_Source: https://www.imf.org/-/media/files/publications/wp/2024/english/wpiea2024089-print-pdf.pdf_