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---

### I. Introduction — context and objectives
- Purpose: revisit fiscal regimes for extractive industries (petroleum and mining) in Mexico to inform post-pandemic revenue and efficiency policy choices.
- Key contextual points:
  - Petroleum sector contributes 15 percent of government revenues.
  - Mining sector contributes 0.5 percent of government revenues.
  - Mexico’s non-oil revenue collections are nearly 6 percent of GDP below Latin American peers and about one half those of the OECD average.
  - IMF staff recommended revenue options to raise revenues by 3-4 percent of GDP over the medium term (IMF 2020).
- Policy framing: review aims to identify reforms to taxation of natural resources that could raise revenues and enhance efficiency, noting Pemex’s financial challenges and likely continued fiscal support.

### A. Mining — summary findings and reform potential
- Sector economic importance:
  - Contributes just over 1 percent of GDP and exports.
  - Approximately 400,000 direct jobs.
- Fiscal contribution (exact figures highlighted in source):
  - Direct taxes on production and profit: about 0.1 percent of GDP, or 0.5 percent of total government revenue.
  - Authorities reported total revenue contributions from the sector of MXN 51 billion in 2019, or approximately 0.2 percent of GDP.
  - Mining revenues amounted to about MXN 29 billion, or about 0.12 percent of GDP, in 2019.
- Current regime characteristics:
  - Flat 0.5 percent royalty for gold and silver.
  - Statutory 30 percent corporate income tax.
  - 7.5 percent additional profits tax.
  - Surface rental payments creditable against the additional profits tax.
  - 10 percent unpaid or ‘free’ equity participation to workers.
  - No ringfencing by mine or license area for corporate income tax or additional profit tax.
  - Additional profits tax base approximates EBIT with restrictions; differs from a pure rent base due to depreciation and deduction rules.
- Design issues and recommendations:
  - Regime is fragmented and implies a moderate average effective tax rate toward the lower end internationally.
  - Consider reform to provide a steady stream of revenue from the start of production and allow government to share in upside of more profitable projects.
  - Stylized reform example could lead to direct tax collections on mining profit and production of about 0.2 percent of GDP (requires detailed design/calibration).
  - Further analysis warranted on whether the 10 percent unpaid equity participation burden is offset by lower wages.

### B. Petroleum — Pemex, fiscal changes, and implications
- Recent fiscal measures for Pemex:
  - Cost deduction caps aligned with production sharing contracts introduced in 2019.
  - Profit-sharing rate: reduced from 65 percent in 2019 to 58 percent in 2020 and 54 percent in 2021.
  - In 2021, a tax benefit granted by Presidential Decree of MXN 73,250 million, equivalent to a profit sharing rate reduction to 40 percent; a permanent reduction was proposed in the draft 2022 budget.
- Policy environment and investment decisions:
  - New licensing rounds to solicit private investment were suspended; authorities looked to Pemex to undertake new upstream investment.
  - State investment in downstream refining including Dos Bocas refinery (originally slated for completion in mid-2022 at a cost of USD 8 billion) subject to cost and time overruns.
  - Pemex agreed in May 2021 to pay USD 0.6 billion to Shell for remaining 50 percent of Deer Park refinery.
- Financial condition and fiscal support:
  - Pemex has continued to run sizable after-tax deficits (negative free cash flow).
  - Credit rating downgraded to speculative grade in 2020; noted as the world’s largest “fallen angel”.
  - External borrowing costs are notably higher than the Mexican government’s.
  - Fiscal support averaged about 1 percent of GDP per year during 2019-21, including equity injections, fiscal transfers, debt repayments, pension liabilities, and tax breaks.
  - Recurrent fiscal support implies lower resources for other priorities, including social spending.
- Recommended comprehensive approach (IMF 2020 highlights):
  - Reform Pemex’s business plan to focus production only in profitable fields, sell non-core assets, curb loss-making refining expansion, postpone new refinery plans until profitable.
  - Partner with private firms to supply capital and expertise.
  - Reform corporate governance and procurement processes.
  - Conditional fiscal support could be considered if business strategy and governance improve.
- Fiscal regime assessment:
  - Increasing cost caps and lowering profit-sharing rates reduce Pemex’s overall tax burden and regressivity and may free funds for investment.
  - Even with these changes, the regime lacks sufficient progressive instruments to allow government to share in upside; migrating entitlement assets to more balanced contractual regimes would be beneficial.

### II. Principles for extractive industries’ fiscal regime design
- Core challenge: balance securing government revenue share with incentives for company investment under uncertainty in production, prices, and costs.
- Recommended instrument mix (as noted in IMF 2012):
  - (i) Production-based instrument (e.g., ad valorem royalty) to ensure minimum revenue when production is positive; should be moderate to avoid deterring investment or increasing cut-off grades.
  - (ii) Corporate income tax with sector-tailored rules; allow relatively quick payback of initial investments while limiting tax erosion.
  - (iii) Additional resource rent capture mechanism (progressive instruments such as resource rent taxes, profit-based production sharing, additional profits tax) to tax immobile rents and share in high profitability.
- Trade-offs:
  - Balance of instruments depends on government revenue objectives and risk preferences.
  - Governments able to bear more risk can structure regimes that shift risk to the state while achieving higher expected tax rates in profitable projects; governments with pressing revenue needs may prefer more certain revenues today.

### III. Mexico’s mining fiscal regime — details and modeling
- Regime type: royalty-tax system.
- Sector-specific observations:
  - Sector-specific direct taxes amount to approximately 10 percent of the total value of mineral production.
- Economic modeling (FARI framework; stylized projects and baseline assumptions):
  - Baseline scenario prices: gold USD 1600 per ounce; copper USD 8000 per ton.
  - Under baseline prices, stylized gold and copper projects generate pre-tax returns of 53 percent and 21 percent, respectively.
- FARI illustrative regime design:
  - 5 percent royalty for all mineral types.
  - 30 percent statutory corporate income tax.
  - 15 percent resource rent tax taking effect once the project reaches a 12.5 percent rate of return.
- FARI AETR results (discounted, 10 percent discount rate):
  - Gold project: 46 percent.
  - Copper project: 45 percent.
  - Illustrative regime increases AETR to the middle of international comparator range.
- Neutrality — breakeven prices (investor minimum after-tax rate of return assumed 12.5 percent):
  - Gold breakeven price: USD 1152/oz.
  - Copper breakeven price: USD 7037/ton.
- Progressivity:
  - Mexico’s current mining fiscal regime displays limited progressivity: AETR remains relatively constant across profitability levels.
  - Illustrative regime (5 percent royalty + additional profit tax with 12.5 percent threshold) improves progressivity.
- Estimated revenue implications (exact figures from source):
  - Increase in AETR from approximately 40 to 55–60 percent would imply a 40–50 percent increase in government revenues.
  - From approximately MXN 30 billion in 2019, this would imply an increase in revenue to MXN 45 billion (0.2 percent of GDP).

### Box 1 (FARI) — metrics and scope
- FARI model: discounted cash flow model reflecting tax accounting rules and specific tax payments; assumes constant factors.
- Investor-perspective indicators:
  - Post-tax NPV of the project.
  - Post-tax internal rate of return.
  - Payback period.
  - Breakeven price.
- Government-perspective indicators:
  - Average effective tax rate (AETR) — “government’s take”.
  - Marginal effective tax rate (METR).
  - Progressivity of the fiscal regime.
- AETR calculated in undiscounted and discounted terms using a discount rate of 10 percent.
- Modeling choices for Mexico:
  - Only principal direct taxes on production and profit modeled; surface rentals not modeled.
  - Project-level analysis; consolidated ringfencing treatment not analyzed.

### Box 2 — Summary of 2012 report findings relevant to petroleum
- 2012 fiscal regime main instruments:
  - Stabilization Fund Duty (DSHFE): 10 percent royalty when oil prices exceeded $31 per barrel.
  - Extraordinary Export Duty: 13.1 percent royalty, creditable against the DSHFE.
  - Ordinary duty: 71.5 percent income tax, subject to a cost cap of $6.50/bbl.
- Under assumptions of oil price $115 per barrel and industry benchmark costs $7.5 per barrel:
  - The 2012 fiscal regime generated AETR in the range 70–80 percent.
  - Sensitivity analysis: over a $50–80 price range, the ordinary regime generated AETR of over 100 percent for representative projects, rendering them unviable at industry benchmark and Pemex cost levels.
- Entitlement fiscal regime principal components and preserved numeric terms (2019):
  - Production Sharing Fee (percent of value of hydrocarbons): 65%
  - Cost Depreciation: 100% expensing of exploration Costs, 4 year straight-line depreciation of development costs
  - Cap on Cost Deductions (percent of value of hydrocarbons):
    - Onshore Oil minimum of 12.5 percent or $8.3/barrel
    - Offshore Oil Shallow minimum of 12.5 percent or $6.1/barrel
    - Offshore Oil Deep 60%
    - Natural Gas 80%
    - Chicontepec 60%
  - Hydrocarbon Extraction Fee (percent of value of hydrocarbons): When oil price is less than $48 per barrel, 7.5%. When oil price greater than or equal to $48 per barrel, 12.5% + (Petroleum price *1 .5)%
  - Corporate Income Tax Rate: 30 percent
  - Depreciation: 100 percent immediate expensing of exploration Costs, 4 year straight-line depreciation of development Costs
- Key 2012 conclusions and policy recommendations:
  - Eliminate the cost cap.
  - Align the fiscal regime with normal IOC taxation.
  - Narrow the gap between Pemex and industry benchmark costs.
  - Strengthen audit controls and independent oversight.
  - Consider interim adjustments to the cap to reduce distortionary effects.

### Petroleum modeling — stylized shallow water project (key exact figures)
- Modeling assumptions and project-level figures (2019 constant dollars unless noted):
  - Constant oil price used in analysis: USD 60 per barrel (note text also cites USD 60.7/Bbl in variant).
  - Pre-tax IRR: 35 percent.
  - Project production: 500 MMBbl total over 18 years.
  - Project costs:
    - Exploration costs: $MM 400; $/Bbl 0.80
    - Development costs excluding drilling: $MM 2,208; $/Bbl 4.42
    - Drilling costs: $MM 1,977; $/Bbl 3.96
    - Operating costs: $MM 3,998; $/Bbl 8.00
    - Decommissioning costs: $MM 558; $/Bbl 1.12
    - Total costs: $MM 9,141; $/Bbl 18.3
- Baseline findings:
  - At assumed price and cost levels, the entitlement regime renders the project unviable.
  - Under entitlement regime with the 12.5 percent cost cap, the project is clearly unviable with an AETR of well over 100 percent, and a 6.8 percent investor IRR.
- Reform effects and exact regime comparisons (selected figures from Table 4):
  - Pre-Tax project IRR: 35.0%
  - Entitlement Regime:
    - Post-tax IRR on total funds: 6.8%
    - Post-tax IRR on equity: 9.0%
    - Pre-tax NCF undiscounted: 20,844
    - Post-tax investor NCF undiscounted: 1,944
    - Government Revenue undiscounted: 18,779
    - AETR undiscounted: 90.1%
    - Pre-tax NCF (10% discount): 5,267
    - Post-tax investor NCF (10% discount): -350
    - Government revenue (10% discount): 5,510
    - AETR (10% discount): 104.6%
  - Entitlement Regime — 2019 Reforms:
    - Post-tax IRR on total funds: 20.9%
    - Post-tax IRR on equity: 32.1%
    - Pre-tax NCF undiscounted: 20,844
    - Post-tax investor NCF undiscounted: 7,478
    - Government Revenue undiscounted: 13,245
    - AETR undiscounted: 63.5%
    - Pre-tax NCF (10% discount): 5,267
    - Post-tax investor NCF (10% discount): 1,449
    - Government revenue (10% discount): 3,711
    - AETR (10% discount): 70.5%
  - Production Sharing Regime:
    - Post-tax IRR on total funds: 18.5%
    - Post-tax IRR on equity: 29.6%
    - Pre-tax NCF undiscounted: 20,844
    - Post-tax investor NCF undiscounted: 5,839
    - Government Revenue undiscounted: 14,884
    - AETR undiscounted: 71.4%
    - Pre-tax NCF (10% discount): 5,267
    - Post-tax investor NCF (10% discount): 1,024
    - Government revenue (10% discount): 4,136
    - AETR (10% discount): 78.5%
- Neutrality — breakeven prices (exact figures from source):
  - Entitlement regime (pre-2019): USD 76.7/barrel
  - Other regimes: 42.0, 38.9 (values appear in figure)

### Progressivity, ringfencing, and macro considerations
- Progressivity findings:
  - Pre-reform entitlement regime: AETR falls as profitability increases (regressive).
  - Increasing cost cap and reducing profit-sharing reduces regressivity but does not introduce substantive progressive components; AETR still falls as profitability increases.
  - PSC regime: progressive components trigger at higher profitability, improving government share on upside.
- Ringfencing:
  - Fiscal payments under entitlement regime are ringfenced by ‘region’ into five classifications; regional ringfencing may reduce incentive for cost efficiency versus asset-level ringfencing.
- Macro and asset-level considerations:
  - Difficult to assess macro-level revenue implications without detailed asset-level information.
  - Increase in cost cap provides more relief for fields still recovering large capital investment costs than for fields with recovered capital costs.
  - Government estimate (exact figures): Combined effect of the 2019 and 2021 measures will reduce government revenue from the Pemex fiscal regime by MXN 78 billion in 2021, and MXN 83 billion in 2022 (around 1.5 percent of government budgetary revenues).

### Climate change mitigation implications for fiscal design
- Expectations:
  - Coal and oil production expected to fall the most over the medium to long run.
  - Share of natural gas in fossil fuel consumption likely to increase.
- Policy trade-off:
  - Prioritize attracting new investment: emphasize profit-based instruments adaptable to a range of profitability outcomes.
  - Prioritize maximizing revenue from existing assets: greater reliance on production-based taxes (royalty or minimum petroleum share).

### Summary findings and policy recommendations (selected exact elements)
- Mining:
  - Room to increase overall tax burden through redesign (e.g., moderate increase in royalty rate, refinement of additional rent tax) while minimizing competitiveness effects.
  - Illustrative scenario shows revenue nearly doubling from 0.1 percent of GDP to 0.2 percent of GDP.
- Petroleum and Pemex:
  - Pre-2019 entitlement incentives to invest are low; 2019–21 measures reduce regressivity and raise attractiveness for investment.
  - Recommended safeguards and complementary measures when increasing cost caps:
    - (i) Careful screening by CNH of Pemex’s projects, budgets and work plans.
    - (ii) Regular high-quality cost and fiscal audits (required by CNH and SAT).
    - (iii) Competitive, transparent procurement procedures for subcontractor services.
  - Consider ringfencing Pemex’s operations at an asset level to encourage greater cost efficiency.
  - Make tax relief such as the 2019-21 measures ideally contingent upon strategic and governance reform within Pemex.
  - Private sector participation through farmouts during migration can provide cost oversight and incentivize cost containment.
- Broader policy direction:
  - Review and potential reform of fiscal regimes for mining and petroleum should be considered within a comprehensive approach including changing Pemex’s business strategy, partnering with private firms, and undertaking governance and procurement reforms.

*Source: wpiea2021245-print-pdf*

### References ________________________________________________________________36

### References ________________________________________________________________36

### I. Introduction — context and objectives
- Purpose: revisit fiscal regimes for extractive industries (petroleum and mining) in Mexico to inform post-pandemic revenue and efficiency policy choices.
- Key contextual points:
  - Petroleum sector contributes 15 percent of government revenues.
  - Mining sector contributes 0.5 percent of government revenues.
  - Mexico’s non-oil revenue collections are nearly 6 percent of GDP below Latin American peers and about one half those of the OECD average.
  - IMF staff recommended revenue options to raise revenues by 3-4 percent of GDP over the medium term (IMF 2020).
- Policy framing: review aims to identify reforms to taxation of natural resources that could raise revenues and enhance efficiency, noting Pemex’s financial challenges and likely continued fiscal support.

### A. Mining — summary findings and reform potential
- Sector economic importance:
  - Contributes just over 1 percent of GDP and exports.
  - Approximately 400,000 direct jobs.
- Fiscal contribution:
  - Direct taxes on production and profit amount to about 0.1 percent of GDP, or 0.5 percent of total government revenue.
  - Authorities reported total revenue contributions from the sector of MXN 51 billion in 2019, or approximately 0.2 percent of GDP.
  - Mining revenues amounted to about MXN 29 billion, or about 0.12 percent of GDP, in 2019.
- Current regime characteristics:
  - Historically minimal sector-specific taxes until 2014.
  - Current instruments: flat 0.5 percent royalty for gold and silver; statutory 30 percent corporate income tax; 7.5 percent additional profits tax; surface rental payments creditable against the additional profits tax; 10 percent unpaid or ‘free’ equity participation to workers.
  - No ringfencing by mine or license area for corporate income tax or additional profit tax.
  - The additional profits tax base approximates EBIT with restrictions; differs from a pure rent base due to depreciation and deduction rules.
- Design issues and recommendations:
  - Regime is fragmented and implies a moderate average effective tax rate toward the lower end internationally.
  - Consider reform to provide a steady stream of revenue from the start of production and allow government to share in upside of more profitable projects.
  - Stylized reform example could lead to direct tax collections on mining profit and production of about 0.2 percent of GDP (requires detailed design/calibration).
  - Further analysis warranted on whether the 10 percent unpaid equity participation burden is offset by lower wages.

### B. Petroleum — Pemex, fiscal changes, and implications
- Pemex role and recent fiscal measures:
  - Pemex’s fiscal regime loosened in 2019 to release funds for investment: cost deduction caps aligned with production sharing contracts; profit-sharing rate reduced from 65 percent in 2019 to 58 percent in 2020 and 54 percent in 2021.
  - In 2021, government granted a tax benefit of MXN 73,250 million by Presidential Decree, equivalent to a profit sharing rate reduction to 40 percent; a permanent reduction was proposed in the draft 2022 budget.
- Policy environment:
  - New licensing rounds to solicit private investment were suspended; authorities looked to Pemex to undertake new upstream investment.
  - State investment in downstream refining including Dos Bocas refinery (originally slated for completion in mid-2022 at a cost of USD 8 billion) subject to cost and time overruns.
  - Pemex agreed in May 2021 to pay USD 0.6 billion to Shell for remaining 50 percent of Deer Park refinery.
- Financial condition and fiscal support:
  - Pemex has continued to run sizable after-tax deficits (negative free cash flow).
  - Credit rating downgraded to speculative grade in 2020; noted as the world’s largest “fallen angel”.
  - External borrowing costs are notably higher than the Mexican government’s.
  - Fiscal support averaged about 1 percent of GDP per year during 2019-21, including equity injections, fiscal transfers, debt repayments, pension liabilities, and tax breaks.
  - Recurrent fiscal support implies lower resources for other priorities, including social spending.
- Recommended comprehensive approach (IMF 2020 highlights):
  - Reform Pemex’s business plan to focus production only in profitable fields, sell non-core assets, curb loss-making refining expansion, postpone new refinery plans until profitable.
  - Partner with private firms to supply capital and expertise.
  - Reform corporate governance and procurement processes.
  - Conditional fiscal support could be considered if business strategy and governance improve.
- Fiscal regime assessment:
  - Increasing cost caps and lowering profit-sharing rates reduce Pemex’s overall tax burden and regressivity and may free funds for investment.
  - Even with these changes, the regime lacks sufficient progressive instruments to allow government to share in upside; migrating entitlement assets to more balanced contractual regimes would be beneficial.

### II. Principles for extractive industries’ fiscal regime design
- Core challenge: balance securing government revenue share with incentives for company investment under uncertainty in production, prices, and costs.
- Recommended instrument mix (as noted in IMF 2012):
  - (i) Production-based instrument (e.g., ad valorem royalty) to ensure minimum revenue when production is positive; should be moderate to avoid deterring investment or increasing cut-off grades.
  - (ii) Corporate income tax with sector-tailored rules; allow relatively quick payback of initial investments while limiting tax erosion.
  - (iii) Additional resource rent capture mechanism (progressive instruments such as resource rent taxes, profit-based production sharing, additional profits tax) to tax immobile rents and share in high profitability.
- Trade-offs:
  - Balance of instruments depends on government revenue objectives and risk preferences.
  - Governments able to bear more risk can structure regimes that shift risk to the state while achieving higher expected tax rates in profitable projects; governments with pressing revenue needs may prefer more certain revenues today.

### III. Mexico’s mining fiscal regime — further details and modeling
- Regime type: royalty-tax system with main instruments listed above.
- Sector-specific observations:
  - Sector-specific direct taxes amount to approximately 10 percent of the total value of mineral production.
  - The regime has a moderate economic significance relative to Mexico’s diversified economy.
- Economic modeling:
  - IMF’s FARI modeling framework used with stylized gold and copper project examples.
  - Baseline scenario prices: gold USD 1600 per ounce; copper USD 8000 per ton.
  - Under these baseline prices, stylized gold and copper projects generate pre-tax returns of 53 percent and 21 percent, respectively.
  - Analysis intended to be illustrative; further refinement requires detailed project economics.

*Source: wpiea2021245-print-pdf - References ________________________________________________________________36*

### Box 1. Fiscal Analysis of Resource Industries (FARI)

### Box 1. Fiscal Analysis of Resource Industries (FARI)

### FARI model description
- FARI estimates the government’s share of a resource project’s total pre-tax net cash flows and the interactions among fiscal regime parameters.
- It is a discounted cash flow model set up to reflect tax accounting rules and specific tax payments to the government.
- FARI focuses on evaluation of the fiscal regime assuming all factors remain constant.

### Metrics used by IMF Fiscal Affairs Department (FAD)
- Investor-perspective indicators:
  - Post-tax NPV of the project
  - Post-tax internal rate of return
  - Payback period
  - Breakeven price
- Government-perspective indicators:
  - Average effective tax rate (AETR) — “government’s take”
  - Marginal effective tax rate (METR)
  - Progressivity of the fiscal regime
- AETR is calculated in undiscounted and discounted terms using a discount rate of 10 percent.

### Application to Mexico’s mining regime (scope and modeling choices)
- Only the principal direct taxes on production and profit were modeled. Surface rentals were not modeled owing to their relatively minor fiscal impact.
- The regimes are analyzed on a project level; consolidated ringfencing treatment applicable to mining companies is not analyzed (benefit of offsetting new investment costs against revenue from currently producing mines is not reflected).

### Illustrative regime design
- Comprises:
  - 5 percent royalty for all mineral types
  - 30 percent statutory corporate income tax
  - 15 percent resource rent tax
- Resource rent tax takes effect once the project reaches a 12.5 percent rate of return (an approximation for the investor’s cost of capital).
- Rationale:
  - A 5 percent royalty provides a more certain revenue stream from the start of production and sits within the regional average.
  - The resource rent tax offsets the regressive impact of royalties and improves progressivity.

### Revenue generating capacity (AETR results)
- Mexican regime discounted AETR:
  - Gold project: 46 percent
  - Copper project: 45 percent
- Mexico’s discounted AETR is relatively low compared with other major producers; in the case of copper, Mexico’s regime is the lowest of all comparators, reflecting the lack of any royalty instrument.
- The illustrative regime (higher royalty and additional profit tax rate) increases the AETR to the middle of the international comparator range.

### Neutrality (competitiveness and breakeven prices)
- Neutrality assesses the breakeven price required to meet the investor’s minimum after-tax rate of return (assumed 12.5 percent in real terms).
- Mexico’s mining fiscal regime is competitive with relatively low breakeven prices:
  - Gold breakeven price: USD 1152/oz
  - Copper breakeven price: USD 7037/ton
- Increasing the royalty rate to 5 percent raises the breakeven price but still remains within the comparator range.

### Progressivity
- Progressivity measures the government’s ability to share in upside when profitability is higher (AETR across different profitability levels).
- Mexico’s current mining fiscal regime displays limited progressivity: AETR remains relatively constant at all levels of profitability due to lack of a significant production-based instrument.
- Under the illustrative regime, the higher royalty plus an additional profit tax with a 12.5 percent rate of return threshold improves progressivity by better taxing resource rents.

### Summary findings and fiscal implications
- There is room to increase the overall tax burden on mining through redesign of the system while maintaining balance between production and profit-based instruments to avoid excessive distortion of production decisions.
- A moderate increase in the royalty rate combined with refinement of the additional rent tax to better tax resource rents could increase government take while minimizing competitiveness effects.
- Estimated revenue implications:
  - An increase in AETR from approximately 40 to 55–60 percent would imply a 40–50 percent increase in government revenues.
  - From approximately MXN 30 billion in 2019, this would imply an increase in revenue to MXN 45 billion (0.2 percent of GDP).

### Pemex context (linked sectoral note)
- Background on petroleum sector: oil industry nationalized in 1938; Pemex founded with exclusive rights until energy reform in 2013–14.
- Oil production decline noted:
  - Peak crude oil production in 2004: 3.4 million barrels per day
  - Crude oil production in 2020: 1.6 million barrels per day

*Source: Box 1. Fiscal Analysis of Resource Industries (FARI), wpiea2021245-print-pdf.*

### Box 2. Summary of Findings from 2012 Report

### Box 2. Summary of Findings from 2012 Report

### Assessment of the 2012 fiscal regime (high-level)
- The 2012 fiscal regime comprised three main instruments:
  - Stabilization Fund Duty (DSHFE): a 10 percent royalty applicable when oil prices exceeded $31 per barrel.
  - Extraordinary Export Duty: a 13.1 percent royalty, creditable against the DSHFE, applied to the difference between the actual and the budget oil price.
  - Ordinary duty: a 71.5 percent income tax, subject to a cost cap of $6.50/bbl.
- A special regime applicable to activities in Chicontepec and in deep water fields was also analyzed.
- Under assumptions of an oil price at prevailing 2012 levels of $115 per barrel and industry benchmark costs of $7.5 per barrel, the report concluded:
  - The 2012 fiscal regime generated average effective tax rates (AETR) in the range 70–80 percent.
  - The AETR was notably higher when assumed costs are in line with Pemex’s costs of $17/barrel.
- Sensitivity analysis showed that over a $50–80 price range, the ordinary regime generated AETR of over 100 percent for representative projects, rendering them unviable at both industry benchmark and Pemex cost levels.
- The regime was identified as regressive in terms of both cost and, for the ordinary regime, price, driven largely by limits on deductibility of costs set at low absolute levels and not indexed by inflation.

### 2012 report conclusions and policy recommendations
- Long-run recommendations:
  - Eliminate the cost cap.
  - Align the fiscal regime with normal IOC taxation.
- Transitional and preparatory recommendations:
  - Narrow the gap between Pemex and industry benchmark costs.
  - Strengthen audit controls and independent oversight.
  - Consider interim adjustments to the cap to reduce distortionary effects.

### Entitlements: structure and incentives to migrate
- Exploration and extraction activities in Mexico are carried out through ‘entitlements’ held by Pemex or ‘contracts’ with private companies.
- Pemex may migrate any existing entitlement to the contractual regime; incentives to migrate include less onerous and more progressive fiscal terms and the possibility to ‘farm out’ or partner with private sector partners.
- There were four farmouts in 2017-18, and none since then.
- The contract type and technical terms are determined by SENER and fiscal terms by the SHCP.
- There are currently 428 entitlement agreements in place between SENER and Pemex.

### Entitlement fiscal regime (principal components and numeric terms)
- Principal components:
  - Profit Sharing Fee of 65 percent of production value (which was reduced to 58 percent in 2020 and 40 percent in 2021) less cost deductions, which are subject to an annual cost cap.
  - Hydrocarbons Extraction Fee, essentially a price linked ad-valorem royalty.
  - Corporate Income Tax at 30 percent of taxable income.
- The entitlement regime also includes two annual fixed surface area fees: the Hydrocarbon Exploration Fee, and the Tax on Hydrocarbon Exploration and Extraction Activity. The profit-sharing fee and both hydrocarbons fees are deductible expenses for the calculation of corporate income tax.
- Table 1 key fiscal terms (2019) — preserved values from source:
  - Production Sharing Fee (percent of value of hydrocarbons): 65%
  - Cost Depreciation: 100% expensing of exploration Costs, 4 year straight-line depreciation of development costs
  - Cap on Cost Deductions (percent of value of hydrocarbons):
    - Onshore Oil minimum of 12.5 percent or $8.3/barrel
    - Offshore Oil Shallow minimum of 12.5 percent or $6.1/barrel
    - Offshore Oil Deep 60%
    - Natural Gas 80%
    - Chicontepec 60%
  - Hydrocarbon Extraction Fee (percent of value of hydrocarbons): When oil price is less than $48 per barrel, 7.5%. When oil price greater than or equal to $48 per barrel, 12.5% + (Petroleum price *1 .5)%
  - Corporate Income Tax Rate: 30 percent
  - Depreciation: 100 percent immediate expensing of exploration Costs, 4 year straight-line depreciation of development Costs

### Cost caps, minimum government share, and regressivity
- Prior to the 2014 reform, cost caps were calculated annually in absolute monetary terms; reforms introduced caps expressed as a percentage of revenue in the Hydrocarbons Revenue Law, ranging from 12.5 percent to 80 percent depending on activity location and hydrocarbon type.
- In 2016, minimum levels for cost deductions were introduced for onshore and shallow water projects at USD 8.3 and USD 6.1 per barrel respectively.
- The cost caps act like a royalty by securing up-front revenues to the government as soon as production starts, creating a floor for the government share of project revenues regardless of project profitability.
- For onshore and shallow water offshore oil operations, the combined impact of the royalty and profit-sharing fee has the effect of a royalty of 60.1 percent.
- The report notes:
  - High minimum government shares are regressive and fall most heavily on less profitable projects, increasing investor-perceived risk by lengthening recovery/payback periods and increasing the risk that not all costs will be recovered.
  - Mexico’s effective royalty rate for oil under the entitlement regime is far above international norms; the average effective royalty rate in a sample of 63 countries surveyed is approximately 18 percent.

### Potential adjustments to improve investment incentives
- Increasing the cost cap and lowering the profit-sharing rate reduce the regressive impact for onshore and shallow water offshore oil projects.
- The measures that increase the cost cap and lower the profit-sharing rate could reduce the minimum government share of revenue to 22.3 percent and may facilitate investment on commercial terms.
- Such measures should be part of a comprehensive reform of Pemex’s strategy, including modernizing its business plan and enabling decision-making on a commercial basis to incentivize investment by Pemex and private operators when the playing field is levelled.

### Ringfencing
- Fiscal payments made by Pemex under the entitlement regime are ringfenced by ‘region’ into five regional classifications: onshore, shallow water, deep-water areas, extraction of non-associated natural gas, and extraction in the Chicontepec Paleochannel.
- Regional ringfencing (rather than license- or asset-level ringfencing) may reduce the incentive for cost efficiency and can defer government revenue because Pemex can deduct exploration or development costs for new projects against income of producing projects unless constrained by the cost cap.

### Contractual regimes and 2014 reforms
- Post-2014 legal framework provided different contract types (license contracts, production-sharing contracts, profit-sharing contracts and service contracts) with varying fiscal regimes; some terms specified in Hydrocarbons Revenue Law and others as biddable variables.
- From 2015 to 2018:
  - License contracts were awarded for onshore and deep-water areas.
  - Production sharing contracts were concluded for shallow water areas.
- Following reprioritization toward Pemex since late 2018, there have been no further license contracts or production sharing contracts.
- The 2019 measures sought to align Pemex cost caps with PSC cost recovery limits: cost recovery limit under PSCs was set at 60 percent for oil and 80 percent for gas.
- The 2019 measures lowered the profit-sharing rate to align it more closely with minimum profit share levels under recent PSCs.
  - Analysis of bidding rounds 1, 2 and 3 suggests the average first tier (government) profit share bid was 54 percent for shallow water oil PSCs.
  - The PSC regime is assumed in the note’s modeling to have a minimum government profit petroleum share of 55 percent.

### Economic modeling (stylized project example and key statistics)
- Modeling used FAD’s FARI framework and a stylized shallow water offshore oil field example.
- Key modeling assumptions and project-level figures (all figures in 2019 constant dollars unless otherwise noted):
  - Constant oil price used in the analysis: USD 60 per barrel.
  - Under these assumptions, the project yields a pre-tax IRR of 35 percent.
  - Project production: 500 MMBbl total over 18 years.
  - Project costs:
    - Exploration costs: $MM 400; $/Bbl 0.80
    - Development costs excluding drilling: $MM 2,208; $/Bbl 4.42
    - Drilling costs: $MM 1,977; $/Bbl 3.96
    - Operating costs: $MM 3,998; $/Bbl 8.00
    - Decommissioning costs: $MM 558; $/Bbl 1.12
    - Total costs: $MM 9,141; $/Bbl 18.3
  - Oil Price: $60/Bbl
  - Pre-tax IRR: 35 percent

_Source: Cheasty et al., 2012, ‘Mexico: Is Pemex Taxed Too Much?’, IMF Technical Assistance Report._

### 35.0 percent

### wpiea2021245-print-pdf - 35.0 percent

### Revenue Generating Capacity
- The Average Effective Tax Rate (AETR) or “government take” is defined as the ratio of government revenue from a profitable project to the project’s pre-tax net cash flows, calculated both in undiscounted and discounted terms using a discount rate of 10 percent.
- Project description (note text variants in source):
  - Size: 500 MMBbl
  - Costs: $18.3/Bbl (real)
  - Oil price: $60.7/Bbl (real) (also appears as $60.0/Bbl in figure caption)
  - IRR pre tax: 35 percent
  - Discount Rate used for NPV: 10.0 Percent
- Key qualitative finding:
  - At the assumed price and cost levels, the entitlement regime renders the project unviable.
  - Under the entitlement regime with the 12.5 percent cost cap, the project is clearly unviable with an AETR of well over 100 percent, and a 6.8 percent investor IRR.
  - Regional ringfencing treatment may partially ameliorate this by allowing costs to be recoverable from other projects unless constrained by the cost cap.
- Reform effects:
  - Increasing the cost cap and reducing the profit-sharing rate to 40 percent significantly improves viability: discounted AETR falls to 70.5 percent, with investor IRR of 20.5 percent (text).
  - The PSC regime yields AETR of 78.5 percent, with post-tax IRR of 18.5 percent; higher AETR relative to the reformed entitlement regime largely reflects a higher minimum profit sharing rate (assumed at 54 percent) under the modeled PSC regime.

### Project Fiscal Results (Selected exact figures from Table 4; % or US$ mm real 2019 terms)
- Project parameters across regimes:
  - Pre-Tax project IRR: 35.0% (Entitlement Regime / Entitlement Regime - 2019 Reforms / Production Sharing Regime)
- Entitlement Regime
  - Post-tax IRR on total funds: 6.8%
  - Post-tax IRR on equity: 9.0%
  - Pre-tax NCF undiscounted: 20,844
  - Post-tax investor NCF undiscounted: 1,944
  - Government Revenue undiscounted: 18,779
  - AETR undiscounted: 90.1%
  - Pre-tax NCF (10% discount): 5,267
  - Post-tax investor NCF (10% discount): -350
  - Government revenue (10% discount): 5,510
  - AETR (10% discount): 104.6%
- Entitlement Regime — 2019 Reforms
  - Post-tax IRR on total funds: 20.9%
  - Post-tax IRR on equity: 32.1%
  - Pre-tax NCF undiscounted: 20,844
  - Post-tax investor NCF undiscounted: 7,478
  - Government Revenue undiscounted: 13,245
  - AETR undiscounted: 63.5%
  - Pre-tax NCF (10% discount): 5,267
  - Post-tax investor NCF (10% discount): 1,449
  - Government revenue (10% discount): 3,711
  - AETR (10% discount): 70.5%
- Production Sharing Regime
  - Post-tax IRR on total funds: 18.5%
  - Post-tax IRR on equity: 29.6%
  - Pre-tax NCF undiscounted: 20,844
  - Post-tax investor NCF undiscounted: 5,839
  - Government Revenue undiscounted: 14,884
  - AETR undiscounted: 71.4%
  - Pre-tax NCF (10% discount): 5,267
  - Post-tax investor NCF (10% discount): 1,024
  - Government revenue (10% discount): 4,136
  - AETR (10% discount): 78.5%

### Profile of Government Revenues
- Under the entitlement regime, government takes significant revenues from the commencement of production due to royalty and minimum production share/profit sharing fee.
- The 12.5 percent cost cap yields especially high government take from early cashflows.
- Raising the cost cap to 60 percent and lowering the profit sharing rate to 40 percent provides relief to the investor in early years while recovering investment.
- Production sharing systems provide further relief to investors during investment recovery via uplifts on exploration and development costs.

### Neutrality — Breakeven Price
- Breakeven price defined as the minimum price required to meet the minimum after-tax rate of return assumed at 12.5 percent in real terms.
- Exact breakeven prices highlighted:
  - Entitlement regime (pre-2019): USD 76.7/barrel
  - Other regimes (figures shown elsewhere in source): 42.0, 38.9 (values appear in figure)
- Comparative observation:
  - The entitlement regime’s breakeven price is well above current price levels at USD 76.7/barrel.
  - The entitlement regime with increased cost cap and lower profit-sharing rate, and the production sharing regime, display breakeven prices more in line with current market trends and expectations.

### Progressivity
- AETR variation over project pre-tax IRRs was obtained by varying oil prices and unit costs.
- Findings:
  - Under the pre-reform entitlement regime, AETR falls as profitability increases (regressive).
  - Increasing the cost cap and reducing profit-sharing reduces regressivity but does not introduce substantively progressive components; AETR still falls as profitability increases.
  - Under the PSC regime, AETR initially falls with profitability due to regressive components but is counteracted by progressive components once higher tiers of the production sharing mechanism are triggered.
- Implication:
  - A wider range of projects could be commercially developed under the reformed entitlement regime and the PSC regime. Projects that are commercially viable under reformed regimes would not be developed under the current entitlement regime, so government revenue from such projects would be zero under pre-2019 rules.

### International Comparison
- Comparators include Angola, Norway, Indonesia, Colombia, Brazil, China — using a range of production sharing and additional profits tax mechanisms.
- Key comparisons:
  - The pre-2019 entitlement regime places a significantly higher burden on projects than the other countries in the sample.
  - The PSC and the reformed entitlement regime place Mexico better in line with the sample in terms of neutrality while maintaining comparable government share of revenue.
  - In terms of progressivity, the PSC regime places Mexico in line with regimes linking production sharing to profitability indicators (e.g., Angolan rate-of-return linked production sharing) or with additional profit tax mechanisms (e.g., Norwegian Special Petroleum Tax).

### Macro and Asset-level Considerations
- It is challenging to assess macro-level revenue implications without detailed asset-level information for each entitlement (size, stage of development, financial position).
- The increase in the cost cap will provide more relief for fields still recovering large capital investment costs than for fields that have recovered capital costs and now incur mainly operating costs.
- The distribution of assets within and across regional ringfencing will determine the broader revenue impact and effectiveness of recent measures.
- Government estimate (exact figures):
  - Combined effect of the 2019 and 2021 measures will reduce government revenue from the Pemex fiscal regime by MXN 78 billion in 2021, and MXN 83 billion in 2022 (around 1.5 percent of government budgetary revenues).

### Implications of Climate Change Mitigation Efforts
- Context: global climate change mitigation efforts create uncertainty around baseline fossil fuel use and impacts on fossil fuel production and prices.
- Expectations:
  - Coal and oil production are expected to fall the most over the medium to long run.
  - Share of natural gas in fossil fuel consumption likely to increase given its somewhat lower carbon emissions.
- Policy trade-off:
  - Countries face a choice between reducing government take to compete for a declining pool of investment (to attract new investment) versus maximizing revenue from remaining production from already developed assets.
  - If priority is attracting new investment, a fiscal regime emphasizing profit-based instruments that adapts to a range of profitability outcomes is preferable.
  - If priority is maximizing revenue from existing assets, greater reliance on production-based taxes (royalty or minimum petroleum share) provides more revenue certainty during the transition.

### Summary Findings for the Petroleum Regime and Policy Recommendations
- Main findings:
  - In the context of a comprehensive reform of Pemex’s business strategy, measures to increase the cost cap and lower the profit-sharing rate reduce the regressivity of the petroleum fiscal regime, increase returns to Pemex, and should improve its ability to undertake new onshore and shallow water projects on a commercial basis and increase available cashflow for additional investment.
  - Even with increased cost cap and reduced profit-sharing rate, the regime lacks sufficient progressive instruments to allow the government to share in upside from new developments.
- Recommended safeguards and complementary measures when increasing cost caps:
  - (i) Careful screening by CNH of Pemex’s projects, budgets and work plans.
  - (ii) Regular high-quality cost and fiscal audits (required by CNH and SAT, the Tax Administration Service).
  - (iii) Competitive, transparent procurement procedures for subcontractor services.
  - Consider ringfencing Pemex’s operations at an asset level to encourage greater cost efficiency.
  - Make tax relief such as the 2019-21 measures ideally contingent upon strategic and governance reform within Pemex.
  - Private sector participation through farmouts during migration can provide cost oversight and incentivize cost containment.

### Conclusions (selected exact text elements)
- Contextual factors: elevated commodity prices; Mexico’s large extractive industries; financial challenges of Pemex lowering net fiscal revenues and implying continued weak investment by Pemex; imperative for greater government revenues to finance needed social spending and quality public investment over the medium term.
- Policy directions:
  - Review and potential reform of fiscal regimes for mining and petroleum should be considered within a comprehensive approach, including changing Pemex’s business strategy to focus on profitable fields, sell non-core assets, make refining and investment decisions on commercial terms, partner with private firms for expertise and financing, and undertake governance and procurement reforms.
  - For mining: room to increase overall tax burden through redesign (e.g., moderate increase in royalty rate, refinement of additional rent tax) while minimizing competitiveness effects; illustrative scenario shows revenue nearly doubling from 0.1 percent of GDP to 0.2 percent of GDP.
  - For petroleum: incentives to invest under the pre-2019 regime are low; 2019–21 measures reduce regressivity and raise attractiveness for investment; consideration should be given to enhancing progressive, profit-based instruments to share in upside from new developments.
  - Consider climate change mitigation significance; use of more flexible profit-based instruments could be appropriate.

*Source: wpiea2021245-print-pdf - 35.0 percent*

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_Source: https://www.imf.org/-/media/files/publications/wp/2021/english/wpiea2021245-print-pdf.pdf_