Selected Issues


Selected Issues

Pemex’s Taxation Regime1

Using the IMF Fiscal Analysis for Resource Industries (FARI) project-level cashflow modeling methodology, this note evaluates key characteristics of the current tax regime for PEMEX, and compares it to both recently announced reform plans, as well as the production sharing regime which applies to contracts awarded in recent licensing rounds. The analysis suggests that in the short-term, an increase in the cost cap and a reduction in the profit-sharing rate will not only reduce the overall tax burden for Pemex but also the regressivity of the regime, and by increasing the return to PEMEX, may release funds for further investment. However, the analysis shows that even with the increased cost cap and reduced profit-sharing rate, the regime does not contain sufficient progressive instruments to allow the government to share in the upside from new developments, a desirable characteristic of petroleum fiscal regimes. In the longer term, migration of entitlement assets to the newer more balanced contractual regimes would be beneficial.

A. Introduction

1. The administration is implementing reforms of the petroleum fiscal regime applicable to PEMEX, the state- owned oil company.2 The discussion is based on the premise that the company’s upstream petroleum activities are taxed too heavily, constraining its ability to invest in exploration and production, and intend to release funds for additional investment. Ratings agencies and financial research have also noted the heavy tax burden as a constraint on the company’s ability to finance its capital expenditure program.3

2. This year’s reforms involve both a loosening of cost deduction caps as well as a reduction in the profit-sharing rate. In February 2019, the SHCP announced plans to ease the tax burden by loosening the cost deduction caps under PEMEX’s ‘entitlement’ fiscal regime, aligning them with the cost recovery limits of production sharing contracts concluded under licensing rounds held in 2015–18, and PEMEX’s Ek Balam area which recently transitioned from the entitlement regime to a production sharing contractual scheme. Furthermore, the PEMEX business plan presented in July 2019 announced the government’s plans to reduce the profit-sharing rate from 65 percent to 58 and 54 percent in 2020 and 2021, respectively.

B. Background

3. The petroleum sector in Mexico has a long history of public ownership, with only recent private sector participation. The oil industry was nationalized in 1938 and the state-owned oil company PEMEX was founded, with exclusive rights over exploration, extraction, refining, and commercialization of oil in Mexico. This arrangement lasted until 2013–14, when a wide-reaching Mexican energy reform opened the petroleum sector to private companies, allowing the state to enter into a range of risk-sharing contracts with the private sector. However, under the ‘Round Zero’ process of the reform, SENER granted PEMEX rights over 83 percent of proven and probable reserves and 21 percent of Mexico’s prospective reserves. As such, most of the current petroleum production and the associated revenue is still generated through PEMEX’s operations.

4. As oil production declined PEMEX has faced growing difficulties. Mexico experienced falling crude oil and natural gas production, with crude oil production declining on a sustained basis from its peak in 2004 of 3.4 mbpd. PEMEX had a difficult time fully replacing petroleum reserves. The decline in production and reserve levels was mainly a consequence of the depletion of Mexico’s principal oil field (Cantarell), PEMEX’s lack of the financing and technical capacity required to explore for and develop the majority of its potential resources located in offshore Gulf of Mexico, and the restrictions on private sector participation.

5. While private sector exploration is now increasing, PEMEX is still struggling to undertake capital investment. Since the reform, about 70 companies are now conducting exploration and production in Mexico. Petroleum exploration activity is progressing, with a few significant recent discoveries, and increased production is anticipated over the medium term. However, PEMEX, which still controls a large portion of reserves, is struggling to finance new investment in the sector, blamed in large part to the onerous fiscal regime. PEMEX’s oil production has continued to decline, reaching 1.6 million barrels per day in 2018, less than half of its 2004 peak.

C. Fiscal Regime Reform: Key Design Issues

6. A key challenge in designing a fiscal regime is securing an appropriate level of revenue for the government, while also maintaining incentives for companies to invest in the sector. This must be achieved in the face of uncertain petroleum production, prices or costs across a variety of potential project outturns. Critical to achieving this balance is the composition of the fiscal regime—that is, the balance between production and profit-based instruments. Production-based instruments such as royalties can provide revenues from the start of production but given their regressive nature should be set at a moderate level so as not to deter investment in less profitable projects. Progressive profit-based instruments capture a rising share of cashflows as profitability increases, playing an important role in offsetting the impact of regressive instruments and allowing the government to maintain an appropriate government take across a variety of projects outturns.

7. Progressive instruments commonly feature in modern petroleum fiscal regimes. In recent decades, recognizing the potential for large economic rents in the resource sectors, many petroleum-producing countries in the region and internationally have introduced a range of resource rent taxes, profit-based production sharing and additional profits tax mechanisms to capture additional resource rent as project profitability increases.

8. The appropriate design of PEMEX’s fiscal regime has long been a concern of the Mexican authorities. As a state-owned monopoly, PEMEX has not been subject to the same market discipline as its private sector counterparts. In such an environment, policies must seek to provide an appropriate balance between limiting the operational inefficiencies and cost overruns characteristic of many state-owned corporations, and the risk of creating unwarranted distortions through an overly burdensome tax regime and strict controls which limit the company’s ability to behave as a profit maximizing company. In particular, the design of the fiscal regime has reflected the government’s concerns around the weak incentives for cost containment by PEMEX. Analysis of PEMEX’s regime has been the subject of earlier FAD Technical Assistance reports, most recently in 2012, the findings of which are summarized in Box 1.

Summary of Findings from 2012 Report

The report assessed the fiscal regime in place at the time, which comprised of three main instruments: (i) the Stabilization Fund Duty (DSHFE), a 10 percent royalty applicable when oil prices exceeded $31 per barrel; (iii) the Extraordinary Export Duty, a 13.1 percent royalty, creditable against the DSHFE, applied to the difference between the actual and the budget oil price, and (iii) the ordinary duty, a 71.5 percent income tax, subject to a cost cap of $6.50/bbl. It also analyzed a special regime applicable to activities in Chicontepec and in deep water fields.

Assuming an oil price at prevailing 2012 levels of $115 per barrel, and industry benchmark costs of $7.5 per barrel, the report’s analysis concluded that the 2012 fiscal regime generated average effective tax rates (AETR) in the range 70–80 percent, comparable with other countries in the region (and presenting an improvement over the pre-2005 regime which implied a much higher AETR). The AETR was notably higher when assumed costs are in line with PEMEX’s costs of $17/barrel.

However, the report also acknowledged the regressivity of the regime in terms of both cost and (in the case of the ordinary regime) price, driven largely by the limits on deductibility of costs, which were set at low levels, and in absolute terms, not indexed by inflation. It also presented sensitivity analysis which illustrated that over a $50–80 price range, the ordinary regime generated AETR of over 100 percent, rendering representative projects unviable at both industry benchmark and PEMEX cost levels.

It concluded that in the long run, the cost cap should be eliminated and the fiscal regime aligned with normal IOC taxation. In preparation for this transition, emphasis was placed on the narrowing of the gap between PEMEX and industry benchmark costs, and strengthening of audit controls and independent oversight. It also suggested that interim adjustments to the cap could be considered to reduced its distortionary effects.

Source: Cheasty et al, 2012, ‘Mexico: Is PEMEX Taxed Too Much?, IMF Technical Assistance Report

D. The Mexican Fiscal Regime

9. Exploration and extraction activities in Mexico are carried out either through ‘entitlements’ held by PEMEX, or ‘contracts’ with private companies. While much of PEMEX’s activities are carried out under entitlements, PEMEX now has the option to migrate any existing entitlement to the new contractual regime. Incentives to move to the new regime include less onerous and more progressive fiscal terms, and the possibility to ‘farm out’ or partner with private sector partners. Indeed, one of the ideas behind the reform was to gradually transition PEMEX’s operations to the new contractual regime. In order to make such a transition, PEMEX is required to demonstrate that this will be of benefit to the nation. The contract type and the technical terms are determined by SENER and the fiscal terms are established by the SHCP. In the case of a farm out, PEMEX’s joint venture partners are determined through a public tender process.

E. Entitlements

10. An entitlement is a contract through which the Ministry of Energy (SENER) can grant PEMEX (or another state productive enterprise) the right to explore and produce hydrocarbons. The entitlement holder can then conclude service contracts with private companies for exploration and extraction activities. There are currently 428 entitlement agreements in place between SENER and PEMEX.

11. The entitlements granted to PEMEX are subject to a specific fiscal regime, composed of production and area-based instruments, along with the corporate income tax. This regime is comprised of the following principal components, also detailed in Table 1. These terms reflect the regime prior to the changes contemplated by the SHCP this year.

  • Profit Sharing Fee of 65 percent of production value 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.

Table 1.

Mexico: Entitlement Fiscal Regime

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Source: Hydrocarbons Revenue Law

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 hydrocarbons fees are deductible expenses for the calculation of corporate income tax.

Cost Caps

12. The cost caps associated with the profit-sharing fee reflect an effort to try and contain costs. Prior to the 2014 reform, cost caps were calculated annually in absolute monetary terms, from agreed annual portfolio–wide expenditures by PEMEX divided by the number of barrels expected to be produced in the year. The reforms saw the introduction of caps expressed as a percentage of revenue in the Hydrocarbons Revenue Law, ranging from 12.5 percent to 80 percent depending on the location of the activity (onshore or offshore) and the type of hydrocarbon being extracted (oil or gas). The relatively low level of the cost caps appear to be driven by both the low operating costs associated with the Cantarell field, as well as the government’s experience of cost inflation issues in PEMEX.

13. An important determinant of the fiscal regime’s impact on marginal or less profitable projects is the minimum government share of project revenues, or the ‘effective royalty rate’. Under the entitlement regime, this minimum share results from the Hydrocarbon Extraction Fee and the effect of the cost cap limit combined with the profit-sharing fee. The cap on cost deductions, just like a royalty, secures up-front revenues to the government as soon as production starts by ensuring that there is always a minimum quantity of production revenue subject to the profit-sharing fee. The combination of these instruments provides a floor for the government share of project revenues, regardless of project profitability, offering host countries a form of revenue protection by ensuring that the government collects revenue as long as there is production. However, a high minimum government share of project revenues will increase the risk perceived by an investor: the recovery or payback period will be longer due to the lower amount of petroleum available for cost recovery, with an increased risk that not all costs will be recovered over the project life.

14. For onshore and shallow water offshore oil operations, the profit-sharing fee and associated cost cap have a highly regressive impact. Since Mexico is predominantly an oil producer, these terms are highly relevant to PEMEX’s current and future operations. The combined impact of the royalty and profit-sharing fee has the effect of a royalty of 60.1 percent (Table 2). Royalty instruments are regressive in their fiscal impact, falling most heavily on less profitable projects. Thus, while the regime might appear to generate a high level of government revenue at lower levels of profitability, it raises the risk of discouraging investment altogether. In the context of a state-owned sector, this regressive burden of taxation may have simply represented a transfer of revenue from PEMEX to the state. However, given the intention to allow PEMEX to operate on a level playing field with private operators, this regime may be too regressive to allow for investment to be undertaken on commercial terms. This issue is explored further in Section IV.

Table 2.

Mexico: Minimum Government Revenue

(percent of project revenues)

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Source: Hydrocarbons Revenue Law and Staff EstimatesNote: This calculation assumes that the royalty is deductible from the base of the profit sharing fee. The formula for the effective royalty rate is therefore ‘Royalty Rate+(1-Royalty Rate) *(1-Cost Cap Rate)*Profit Sharing Fee’. Note also that at current price levels of approximately $60/barrel, the royalty rate would be higher than the minimum rate, at around 9 percent ((0.125*60)+1.5). On July 3, 2019, the Mexican basket price was $59.33 per barrel.

15. Internationally, effective royalty rates or minimum government share of revenue levels vary significantly from country to country. However, Mexico’s effective royalty rate for oil under the entitlement regime is far above international norms. The median effective rate in a sample of 56 countries surveyed is approximately 20 percent.

16. SHCP’s proposal to increase the cost cap and lower the profit-sharing rate would reduce the regressive impact for onshore and shallow water offshore oil projects. Indeed, low cost caps combined with high profit shares increase the risk perceived by an investor as the recovery period will take longer. Therefore, increasing the cost cap and lowering the profit-sharing rate, and thereby reducing the minimum government share of revenue to 27.5 percent may help to facilitate investment on commercial terms.


17. Fiscal payments made by PEMEX under the entitlement regime are ringfenced by ‘region’. Under the Hydrocarbons Revenue Law, payments under the entitlement regime as well as for income tax are ringfenced accordingly to five ‘regional’ classifications: onshore, shallow water and deep-water areas, extraction of non-associated natural gas, as well as extraction in the Chicontepec Paleochannel, where exploration for unconventional hydrocarbons is taking place. This ‘regional ringfence’ also applies for income tax.

18. Ringfencing at a regional level rather than a licence or asset level may reduce the impact of the cost caps and will defer government revenue. Without reasonably tight ring-fencing at a licence or contract level, PEMEX can deduct exploration or development costs for each new project against the income of producing projects (if they are not also constrained by the cost cap). New investments will therefore result in an immediate reduction of taxable income on existing operations, and government revenue due from profit-based instruments such as the corporate income tax, or the profit sharing fee from producing areas will likely be delayed.

F. Contractual Regimes

19. Following the recent reform, the legal framework provides for a number of different contract types (license contracts, production-sharing contracts, profit-sharing contracts and service contracts), each implying different fiscal regimes. For each contract type, some of the terms are determined under the Hydrocarbons Revenue Law and specified in further detail in model contracts issued for each licensing round, and others are specified as biddable variables to be determined during the tendering process. Contract regimes appear to have a more balanced structure than the entitlement regime, comprising both production and profit-based instruments. The structure of each contract type is detailed in Figure 1.

Figure 1.
Figure 1.

Mexico: Structure of Contractual Regimes

Citation: IMF Staff Country Reports 2019, 337; 10.5089/9781513519043.002.A003

Source: IMF Mexico Fiscal Transparency Evaluation 2018

20. The principal sources of variation in terms across contract areas are the choice of contract and the bid variable. The government has the flexibility to choose the fiscal system for each area tendered and the associated fiscal biddable variables. A natural consequence of this design is that each contract awarded is subject to a slightly different fiscal regime. To date, license contracts have been awarded for onshore and deep-water areas, and production sharing contracts have been concluded for shallow water areas.

21. The Secretaría de Hacienda y Crédito Público (SHCP) is looking to align the PEMEX cost caps with the cost recovery limits of recently signed production sharing contracts (PSC). Given the focus on alignment with cost recovery limits of PSCs, licence contracts are not analyzed further in this note, but could be the subject of further analysis and technical assistance. The cost recovery limit under these production sharing contracts was set at 60 percent for oil contracts and 80 percent for gas, which align with the natural gas and deep-water oil cost caps for entitlements (Table 3). The cost recovery under the recently migrated Ek-Balam contract4, which was specifically referenced in the SHCP circular is also set at 60 percent. Therefore it appears that the onshore and shallow water offshore entitlement regimes and associated cost caps are the primary focus of the SHCP’s recent announcement.

Table 3.

Mexico: Fiscal Terms – Production Sharing Contracts

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Source: Staff calculations.

22. The plan to lower the profit-sharing rate aligns it more closely with the minimum profit share levels under recent PSCs. Analysis of the results of bidding rounds 1, 2 and 3 suggests that the average first tier (government) profit share bid was 54 percent for shallow water oil PSCs— this aligns with the proposed profit-sharing rate in 2021. This average for the minimum government profit share will be used in the fiscal modeling analysis of the PSC regime in Section V. However, the bids appear to have varied widely and further analysis of specific terms under signed contracts should be the subject of future analysis.5

G. The Mexican Fiscal Regime

23. Economic modeling was undertaken using FAD’s FARI modeling framework and a stylized offshore oil field example. The project example is stylized for illustrative purposes, although it is intended to reflect the broad cost structure of prospects that might be anticipated in the shallow water offshore Mexican waters. It reflects the broad scale of the shallow water Ek-Balam project, and the capital and operating costs reflect the levels reported in a PEMEX investor presentation published in November 2018.6 However, there may be significant variation in the cost structures and project economics of PEMEX’s current and future projects in Mexico, and as such the analysis which follows considers a number of possible variations in price and cost which might alter the ultimate project economics. With more detailed information on the economics of current and future PEMEX projects (including for natural gas), the analysis could be refined further.

24. A key variable underpinning the project economics is the oil price. The analysis uses a constant oil price of USD 60 per barrel, based on current price trends and expectations. With these assumptions, the project yields a relatively high pre-tax IRR of 35 percent (Figure 2) i.e., a profitable project on a pre-tax basis.

Figure 2.
Figure 2.

Mexico: Economics of Project Example Evaluated

Citation: IMF Staff Country Reports 2019, 337; 10.5089/9781513519043.002.A003

Note: All figures are in 2019 constant dollars

25. The current fiscal regime applied to PEMEX’s shallow water offshore oil operations is compared with SHCP’s recent reform proposal and the average terms of production sharing contracts signed following recent bid rounds7. Only the principle terms of the regimes, as detailed in Tables 1 and 2 are modeled. Smaller surface area fixed fees are not modeled – these would constitute a fixed fee and have relatively small regressive impact.

26. The regime is analyzed on a project level, and thus the impact of the consolidated ringfencing treatment applicable to PEMEX is not analyzed. As such the benefit to the investor in being able to offset new investment costs against revenue from currently producing fields is not reflected in the results. Further work could consider the impact of the consolidated tax treatment at the ‘regional’ level.

Revenue Generating Capacity

27. The revenue generating capacity of each fiscal regime was evaluated by estimating the Average Effective Tax Rate (AETR) or “government take”. The AETR is defined as the ratio of government revenue from a profitable project to the project’s pre-tax net cash flows and is calculated both in undiscounted and discounted terms using a discount rate of 10 percent. At the assumed price and cost levels, the entitlement regime renders the project unviable. Figure 3 shows the AETR of the regimes, while Table 4 shows the key results.

Figure 3.
Figure 3.

Mexico: Average Effective Tax Rate – AETR for Selected Regimes

Discount Rate 10.0%

Citation: IMF Staff Country Reports 2019, 337; 10.5089/9781513519043.002.A003

Note: Project Description: Size: 500 MMBbl; Costs: $18.3/Bbl (real); Oil price: $60.7/Bbl (real); IRR pre tax: 35%
Table 4.

Mexico: Key Results

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Source: Staff calculations.

28. 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. It should be noted that this may be partially ameliorated by the regional ringfencing treatment which would allow these costs to be recoverable from other projects, unless of course they are also constrained by the cost cap.

29. The analysis of the entitlement regime might therefore support the notion that the tax burden is constraining PEMEX’s ability to invest. For projects comparable to the example analyzed, private sector companies would be unlikely to explore and develop petroleum resources under these fiscal terms. If projects are being undertaken by PEMEX under terms which render them commercially unviable, the fiscal regime may be restricting the possible returns to PEMEX and the availability of capital to reinvest further.

30. Increasing the cost cap and reducing the profit-sharing rate does improve the viability of the project. With the increased cost cap and reduced profit-sharing rate (at 54 percent), the discounted AETR falls significantly to 79.6 percent, with an investor IRR of 18.0 percent.

31. The project is also viable under the PSC regime. The PSC regime generates an AETR of 78.5 percent, with a post-tax IRR of 18.5 percent. The slightly lower AETR, compared with the reformed entitlement regime reflects a more generous cost recovery treatment through the application of cost uplifts.

Profile of Government Revenues

32. Looking at the profile of government revenues, under the entitlement regime, government takes significant revenues from the commencement of production. Figure 4 displays the profile and composition of revenues collected by the government from royalty, profit sharing fee or production sharing and corporate income tax. The profile of government revenue mainly reflects the production profile of the project evaluated. While under all three options the government starts receiving revenue from day one of production (due to the royalty and minimum production share/profit sharing fee), government take from early cashflows is especially high in the case with the 12.5 percent cost caps. Raising the cost cap to 60 percent and lowering the profit sharing rate to 54 percent provides some relief to the investor in the early years of the project while is recovering its investment. This effect is also seen in the case of the production sharing system, where the uplifts on exploration and development costs provide further relief to the investor during the investment recovery period.

Figure 4.
Figure 4.

Mexico: Government Revenue Profile and Composition

Citation: IMF Staff Country Reports 2019, 337; 10.5089/9781513519043.002.A003

Source: Staff Calculations


33. The analysis also compared the relative burden that the different options would put on a marginal project. A key indicator is the “breakeven price” or the minimum price required to meet the minimum after-tax rate of return required by the investor (assumed in the model to be 12.5 percent in real terms).8 As expected, for the entitlement regime, driven by its highly regressive nature, the breakeven price is well above current price levels at USD76.7/barrel (Figure 5). In contrast, by reducing the regressive fiscal burden, 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.

Figure 5.
Figure 5.

Mexico: Breakeven Price

Citation: IMF Staff Country Reports 2019, 337; 10.5089/9781513519043.002.A003

Source: Staff calculations.


34. The analysis then considered how the AETR varies over a range of project outcomes. Progressive instruments in the fiscal regime would yield a higher share for the government as the profitability of the project increases, offsetting the impact of the regressive instruments. Figure 6 below illustrates the AETR over a range of project pre-tax IRRs. The variation in project pre-tax IRR was obtained by varying oil prices and the unit costs of the projects, respectively.

Figure 6.
Figure 6.

Mexico: Progressivity

Citation: IMF Staff Country Reports 2019, 337; 10.5089/9781513519043.002.A003

Source: Staff calculations.

35. While increasing the cost cap and reducing the profit-sharing rate reduces the regressivity of the entitlement regime, without a substantive progressive component, the AETR falls as profitability increases. In contrast, under the PSC regime, while the AETR initially falls as profitability increases due to the dominance of its regressive components, this effect is counteracted by the progressive components once profitability increases enough to trigger the higher tiers of the production sharing mechanism.

36. The results imply that a wider range of projects could be developed commercially under the reformed entitlement regime and the PSC regime. Although it appears that government take from an individual project would be lower under the PSC than the entitlement regime at lower levels of project profitability, it is important to recall that such projects, if based purely on commercial viability, would not be developed at all under the current entitlement regime, and so no government revenue would be available.

International Comparison

37. The Mexican regimes were compared with fiscal regimes applicable in other petroleum producing countries from the region and globally (Figures 7 and 8). Some of the comparators included in the sample are terms in established producers (Angola, Norway, Indonesia), while others are producers in the region (Colombia, Brazil). Under their fiscal regimes, these comparator countries use a range of production sharing and additional profits tax mechanisms to capture resource rents.

Figure 7.
Figure 7.

Government Tax and Breakeven Price—International Comparison

Citation: IMF Staff Country Reports 2019, 337; 10.5089/9781513519043.002.A003

Source: Staff calculations
Figure 8.
Figure 8.

Progressivity—International Comparison

Citation: IMF Staff Country Reports 2019, 337; 10.5089/9781513519043.002.A003

Source: Staff calculations

38. The entitlement regimes place a significantly higher burden on projects than the other countries in the sample. In contrast, the PSC and the reformed entitlement regime places Mexico better in line with the sample in terms of neutrality, while still maintaining a comparable government share of revenue. In terms of progressivity, the PSC regime places Mexico in line with other regime with production sharing linked to profitability indicators such as the Angolan rate of return linked production sharing system, or those with additional profit tax mechanisms such as the Norwegian Special Petroleum Tax.

H. Observations

39. The analysis suggests that in the short term, the increase in the cost cap and a reduction in the profit-sharing rate will reduce the regressivity of the regime. By increasing the return to PEMEX, these reforms would improve its ability to undertake new onshore and shallow water oil projects on a commercial basis and increase its available cashflow for additional investment.

40. However, the analysis shows that even with the increased cost cap and reduced profit-sharing rate, the regime does not contain sufficient progressive instruments to allow the government to share in the upside from new developments, a desirable characteristic of petroleum fiscal regimes. In the longer term, therefore, migration of entitlement assets to the newer more balanced contractual regimes would be beneficial, although this would of course come with some revenue loss to the government.

41. If cost caps are increased, other mechanisms should be put in place to mitigate the risk of cost inflation. These would include: (i) careful screening by CNH of PEMEX’s projects, budgets and work plans; (ii) regular high-quality cost and fiscal audits (which should be required by CNH and SAT, the Tax Administration Service); and (iii) competitive, transparent procurement procedures for subcontractor services. Ultimately, through the migration process, private sector participation through farmouts can provide a mechanism for cost oversight and incentivize cost containment.


Prepared by Alpa Shah.


SHCP Boletín 009–2019, ‘Acciones para fortalecer la capacidad productiva de Petroleos Mexicano’, Ciudad de México, 28 de enero de 2019.


Barclays Credit Research, ‘Petróleos Mexicanos (PEMEX): Crude Awakening; Initiating at Underweight, January 11, 2019.


It is also understood that the Ek-Balam contract has a much higher minimum government share of 70.5 percent. Further analysis would consider the mechanics of this PSC and the basis on which these terms were determined during the migration process.


The PSC regime is assumed to have a minimum government profit petroleum share of 55 percent.


This rate would of course vary by country, depending on the risks to be faced in the exploration and development of potential projects in Mexico.

Mexico: Selected Issues
Author: International Monetary Fund. Western Hemisphere Dept.