Historical Background

Early Mexican E&P

Early in the last century, Mexico became both an important oil producing nation and trendsetter in nationalization of oil industries. In the process it told a cautionary tale of the costs of both an under-regulated investment environment and a heavy-handed, statist approach to conducting a national oil and gas industry.

In 1887, Water Pierce Oil Company, a subsidiary of Standard Oil, became the first foreign-owned oil company to establish operations in Mexico by engaging in the refining of Mexican crude oil and the sale of its products in the United States.

In 1901, President Porfirio Diaz promulgated the first hydrocarbons law, formally opening Mexican oil and gas to direct foreign investment in various forms, including licenses and concessions. U.S., Dutch, French, Canadian and British companies took advantage of the opportunity and in a short time became the dominant force in the country's oil and gas industry. Mexican-owned entities had very little participation in it.

Mexico's popular revolution in 1910 culminated with the promulgation of the 1917 Political Constitution, a fundamental law in which many individual guarantees, particularly those relating to employment, were socialized and endure to this day unmodified. Most importantly, the Constitution declared the nation to be the "original" owner of all natural resources within the territory, including land and water, and reserved to the state the right to expropriate private property for public need and upon indemnification of the affected party. There ensued political and legal proceedings to declare the oil companies' concessions invalid and to reclaim the state's ownership of subsoil hydrocarbons, but the oil companies generally prevailed in the increasingly acrimonious disputes.

The 1938 Expropriation

In 1937, the oil and gas companies that had been engaging in exploration and production for more than 40 years refused to sign a collective bargaining agreement with the then fairly new Mexican oil workers unions. Upon the refusal, the unions collectively declared a national strike and filed an employment claim with the Junta General de Conciliación y Arbitraje, a socialist, pro-worker governmental authority which quickly resolved the claim in favor of the unions and awarded workers 26 million dollars in back pay and other employment-based benefits. The oil companies filed an appeal with the Mexican Supreme Court, but the court declined to grant any relief. As a result, the companies rebelled and refused to pay the award.

In light of the impasse, President Lázaro Cárdenas took matters into his own hands and on March 18, 1938 issued a decree expropriating Mexico's entire private petroleum industry. Shortly thereafter, Mexico's state-run oil company, Petromex (now Petróleos Mexicanos or "Pemex"), was founded to explore for and exploit hydrocarbons on behalf of the State, and the Constitution was further amended to prohibit granting of exploration and production concessions that gave concessionaires rights in and to the hydrocarbons in place.

In the following two decades, participation of private capital in the Mexican oil and gas industry contracted, while the government, through Pemex, consolidated its monopolistic control over it. In 1958, a special law ended risk-service contracts by prohibiting Pemex from making payments to contractors in production or that were calculated based on the value of production. In 1960, President Adolfo López Mateos caused Congress to further amend the Constitution to once and for all prohibit private sector capital participation in the exploration and exploitation of hydrocarbons and annul the validity and legal effects of any remaining upstream concessions and other contracts that had been grandfathered into the hydrocarbons legal regime. This amendment meant oil and gas companies could only purchase production or provide Pemex a service for cash, without any right to the production, to a share thereof, or to cash payments in amounts related to the value of the production.

The Gift of Cantarell

In 1971, Rudecindo Cantarell Jiménez at the behest of a friend visited Pemex's Coatzacoalcos offices and notified the company of a discovery he had made. Fishing in the shallow waters of the Gulf of Mexico ten years earlier, he had spotted bubbles of a black substance floating on the surface 70 kilometers north of Ciudad del Carmen. The substance later was confirmed to be crude oil and a development plan ensued. The reservoir, later named Cantarell, became the largest crude oil find in Mexico's history, and by 1982 raised total Mexican oil production levels to 2,750,000 barrels/day. 

Despite the notable increase in production, the effects of Mexico's complete rejection of risk capital and other disincentives to investment (including within Pemex, where increasingly harsh rules intended to stem corruption also stunted innovation and risk taking) became evident in the increasingly underdeveloped state of Mexico's oil and gas infrastructure. Reserve replacement suffered and production levels decreased over the next 13 years. In time Mexico, a nation rich in natural gas resources, became a net importer of natural gas.

Some in the country began to realize that its restrictive constitutional and secondary legal provisions, so protective of the state's supremacy in the energy sector, were leading to a failure to fully develop its energy resources and infrastructure. By the mid-1990s, however, the only substantive reform measures that had been undertaken included a restructuring of Pemex's operations (along with substantial reductions in employment), an attempt to sell several chemical units and other non-core operations, and secondary law amendments that permitted private enterprise to obtain a concession to transport, store and distribute natural gas.

Decline and Half-Steps to Liberalization

In 2001, when daily production had reached 3,127,000 barrels/day, slightly above the country's all time high of 1982, the Mexican government took a significant, albeit very small step to liberalize the upstream petroleum industry. In the late fall of such year, President Vicente Fox rallied Congress to amend Mexico's hydrocarbons law, which regulated Article 27 of the Constitution, to allow the implementation of what were then called multiple services contracts (MSCs, and now called contratos de obra pública financiada or COPFs), barely overcoming domestic political opponents who argued that the instrument was an unconstitutional invasion by private investors into the constitutionally protected, exclusive province of the Mexican government.

The MSC embodied a simple, yet seemingly non-controversial idea: a long term, cash fee-based contract that permitted private companies to contract with Pemex for multiple services in connection with the exploration, development and production of natural gas fields in Northeastern Mexico. Under an MSC, one or more contractors performed all the work and bore 100% of the costs required to explore, develop and produce non-associated gas located in a specified contract area, in exchange for a monthly fee paid in cash and calculated according to pre-established "unit prices" for each type of work activity. Notwithstanding the political firestorm they created, these instruments were essentially service contracts, with the private company having no rights to success-related upside or revenue as a function of production or commodity prices. Furthermore, the contractor was paid only if Pemex was able to sell incremental production in amounts sufficient to cover the fees. As a result, the MSC system failed to attract investment and increase natural gas production, and the regime did not bridge the gap between natural gas demand and supply in Mexico; not by a long shot.

By 2004, when production levels had reached an all-time high of 3,382,000 barrels/day, Cantarell began to decline in production, affecting not only Pemex's finances, but the revenues the company generated to fund over 30% of the Mexican national budget. 

In 2008 Mexico again amended its hydrocarbons law seeking to increase revenues by relaxing Pemex's procurement rules and debt restrictions. Under the new rules, Pemex awarded service contracts for the provision of evaluation, development and production services in Mexico's mature southern (2011) and northern (2012) regions. These contracts, referred to by Pemex as contratos de servicios integrales or full service contracts (FSCs), became the first contractual instruments issued by Pemex as part of its broader business strategy of increasing production from mature fields, of further developing reserves in the Chicontepec area and of establishing commercial production in the Mexican deep waters of the Gulf of Mexico. 

Under the FSCs, Pemex paid contractors a fee for base production equal to a percentage (21% in some cases) of an agreed-upon tariff plus a fee for incremental production equal to up to 100% of such tariff; fundamentally, it was a performance-related bonus system, but it skirted the prohibition on making payments in amounts related to the value of production. As with many older service contracts in Latin America, FSCs required that payments be made out of the gross income generated by the sale of crude oil produced from the contract area, but unlike their predecessors, FSCs reduced the gross income to the extent that Pemex's significant fiscal obligations to the federal government left insufficient "available cash" for distribution. Given the obligation Pemex had to pay some 65% of its annual revenues to the federal government, this was a powerful disincentive to oil companies. And following the suit of its predecessor contract, the FSCs failed to attract meaningful investment by the international oil companies in the upstream sector. Likewise, oil companies interested in maintaining a positive reserve replacement ratio were discouraged by the contractual limitations in the FSCs on booking Mexican crude oil reserves.

The Commitment to Constitutional Change

By early 2013 it became painfully evident to the two main political parties in Mexico, namely Partido Acción Nacional (PAN) and Partido Revolucionario Institucional (PRI), that the fundamental obstacle to liberalizing the Mexican oil and gas industry and attracting the capital and technology required to develop hydrocarbons resources necessary to satisfy the country's increasing energy demand, was the country's refusal to amend the Constitutional restrictions. In essence, the Constitution and its regulating laws forced Pemex to experiment with half-steps toward liberalization, and the growing realization that Mexico could not defy market realities and still increase its reserves had sunk in. 

In an unprecedented change in Mexican energy politics, on December 20, 2013 Mexico made that Constitutional change. PAN and PRI joined forces and amended Mexico's Constitution to allow the participation of private capital in its upstream, midstream and downstream oil and gas businesses. 

Under the amended Constitution, Mexico has the ability to legislate the participation of private capital in its oil and gas industry much in the same manner as most producer countries. All types of hydrocarbons under the soil continue to be owned by the Nation, as is in most of the rest of the world, but state and privately-owned domestic and foreign companies may now compete in a free market for and directly engage in the exploration and production of liquid, solid and gaseous hydrocarbons, conventional or unconventional, pursuant to any type of host government instrument the state creates and implements, except for concessions. 

Implementing legislation became effective on August 11, 2014, and detailed regulations are in preparation at the time of this writing, with a first public bid round scheduled for 2015.

Types of E&P Contracts Authorized Under the Reform 

While the nation owns all forms (liquid, solid and gaseous) of subsoil hydrocarbons within the territory, including those located onshore and offshore, the state on behalf of the nation may enter into any type of contract it may create for the exploration and production (E&P) of hydrocarbons. 

The Comisión Nacional de Hidrocarburos (CNH), the upstream regulator, will award all E&P contracts pursuant to a public procurement process governed solely by the provisions of the Hydrocarbons Law. The mechanism to adjudicate a contract may take the form of an ascending-bid auction, a descending-bid auction or a first-price, sealed-bid auction, in which case all envelopes will be opened in the same public session. To pre-qualify for the bid, all bidders will be required to satisfy certain technical, financial, execution and experience capabilities previously established by the Secretaría de Energía (SENER), the ministry of energy. 

Four types of contracts are regulated under the new Hydrocarbons Law and Hydrocarbons Revenues Law, the main legislation governing the upstream oil and gas sector: licenses, profit and production-sharing contracts and service contracts.

Licenses

Under a license, the licensee will acquire the exclusive right to explore for and produce hydrocarbons from a specified area and for a specified term and acquire title to the hydrocarbons it produces at a specified point above the surface. Title will pass from the state to the licensee upon their extraction from the subsoil, provided the licensee is not in default of its payment obligations under the license. 

In exchange for the rights granted to it under the license, a licensee must make the following payments to the Fondo Mexicano del Petróleo para la Estabilización y Desarrollo (FMP), a public trust that has been created to administer all hydrocarbons revenues:

  1. Signing Bonus

At the time the license is granted, a licensee must pay a cash signing bonus set forth in the corresponding bid terms and conditions for a specific license. The amounts of these bonuses will have no relationship to the profitability of the project, and thus are expected to be moderate. Bonuses will be in essence earnest money, and the licensee will not recover its cost until it successfully develops the licensed area.   

  1. Delay Rentals

For each month of the term, a licensee must pay delay rentals for each square kilometer of the licensed area that is not in production. As of the effective date of the Hydrocarbons Revenues Law, the delay rental amount for the first 60 months of a term will be $2,650 Pesos and the delay rental amount for the remainder of a term will be $4,250 Pesos. Both amounts will be adjusted for inflation each January in accordance with variations of the Mexican national consumer price index (Índice Nacional de Precios al Consumidor).  

  1. Royalties

For each month of a term, a licensee must pay royalties for each type of hydrocarbon it produces from a licensed area in an amount equal to a percentage (a royalty rate) of the contractual value of such hydrocarbon. Royalties are calculated over the gross value of all hydrocarbons produced from the licensed area, and thus are free from costs of production. They are also adjusted for inflation in accordance with variations of the Producer Price Index of the United States.

The contractual value of each type of hydrocarbon (i.e., crude oil, natural gas or condensates) is determined by multiplying the volume (measured in barrels or million BTUs, as applicable) of such hydrocarbon times a contractual reference price. Volume is measured each month of a term at pre-agreed measurements points, and the contractual reference price calculated each month of the term in accordance with market value parameters set forth in a license.

The calculation of the royalty rate for each type of hydrocarbon is progressive, meaning that a rate will increase as the contractual reference price increases above a threshold. Thus, the revenue the state receives under a license will increase as the contractual price of hydrocarbons increases above an applicable threshold. However, recognizing that high royalty rates that are free from costs of production may discourage investment in high-cost projects, cause an operator to abandon projects prematurely or otherwise distort an operator's business judgment, the state has established what are arguably moderate royalty rates that are not intended to capture a lion's share of the state's overall oil and gas revenue.

a. Royalty Rate for Crude Oil

If the contractual reference price for crude oil is less than $48 USD per barrel, the royalty rate will be 7.5%. If such price is equal to or greater than $48 USD per barrel, the royalty rate will be equal to: [(0.125 x the contractual reference price) + 1.5]%.

b. Royalty Rate for Associated Natural Gas

The royalty rate will be equal to the quotient of the contractual reference price and 100.

c. Royalty Rate for Non-Associated Natural Gas

If the contractual reference price for non-associated natural gas is less or equal to $5 USD per million BTU, the royalty rate will be 0%. If such price is greater than $5 USD per million BTU but less than $5.50 USD per million BTU, the royalty rate will be equal to:

[(contractual reference price – 5) x 60.5] % contractual reference price

If the contractual reference price is equal to or greater than $5.50 USD per million BTU, the royalty will be equal to the quotient of the contractual reference price and 100.

d. Royalty Rate for Condensates

The calculation of a royalty rate for condensates is similar to the calculation used for crude oil. If the contractual reference price for condensates is less than $60 USD per barrel, the royalty rate will be 5%. If such price is equal to or greater than $60 USD per barrel, the royalty rate will be equal to:

[(0.125 x the contractual reference price) – 2.5] %.  

  1. Overriding Royalties

For each month of a term, a licensee will pay an overriding royalty applicable to each type of hydrocarbon that is produced from a licensed area in an amount equal to a percentage (an overriding royalty rate) of the contractual value of such hydrocarbon.

The overriding royalty will be the mechanism through which the Mexican government generates the lion's share of hydrocarbons revenues under a license. Under the original Hydrocarbons Revenues Law bill, the overriding royalty rate would have applied either to the contractual value of the hydrocarbons produced from a licensed area or to the licensee's operating profits (i.e., the contractual value of such hydrocarbons net of royalties, operating costs and expenses, and investment amortizations), but under the final law rates apply only to the contractual value of hydrocarbons produced from a licensed area. This means that the overriding royalty will be free from costs of production.

aOverriding Royalty Rate

The overriding royalty rate will not be set by CNH, but by each bidder as part of its bid for a license. Most importantly, CNH will award a license to the bidder who proposed the overriding royalty rates that will provide the state the highest revenue.

b. Windfall Profits Adjustment

The state has an express interest in maximizing hydrocarbons revenues in projects with unexpected profitability, and thus, for each license CNH will establish a mechanism for the adjustment of the overriding royalty rate during each month of a term in which such unexpected profits arise; in essence, a mechanism to capture windfall profits from a licensee.  

  1. Taxes

a. Income and Other Taxes

A licensee will pay taxes on its income and all other taxes to which it may be subject under applicable tax laws. Income tax is currently assessed on companies at a rate of 30%. Dividends paid to foreign shareholders are subject to a withholding tax of 10%. Activities that are subject to the payment of value added tax and for which the licensee pays signing bonus, delay rentals, royalties or overriding royalties are taxed at a rate of 0%.

b. E&P Tax

A licensee will also pay a monthly E&P tax per square kilometer of a licensed area. As of the effective date of the Hydrocarbons Revenues Law, the tax during the exploration phase is $1,500 Pesos and the tax during a production phase is $6,000 Pesos.

Production and Profit Sharing Contracts

Under a production or profit sharing agreement, a contractor is given the right to explore for and produce hydrocarbons from a contract area, assuming all exploration risks and costs, in exchange for the reimbursement of recoverable costs and a pre-agreed share of a project's operating profits. The remaining share of operating profits corresponds to the State, along with the payment of delay rentals and overriding royalties that are calculated in the same manner as they are calculated under a license.

  1. Operating Profits

For each month during a term, operating profits will be equal to the contractual value of each type of hydrocarbon produced from a contract area, less (a) the amount of overriding royalties actually paid to the state and (b) the aggregate amount of recoverable costs.

The contractual value of each type of hydrocarbon produced from a contract area under a production or profit sharing contract is determined in the same manner as the contractual value of such hydrocarbon is determined under a license.  

  1. Cost Recovery

The ability of a contractor to recover costs may be limited in three fundamental ways:

a. SHCP Guidelines

The Secretaría de Hacienda y Crédito Público (SHCP), Mexico's department of treasury and top authority under the Hydrocarbons Revenues Law, will periodically publish and update guidelines containing specific criteria that may limit cost recovery.

b. Non-Deductible Costs

Among a list of fifteen types of development and operating costs, a contractor may not recover costs of acquiring rights-of-way, easements or land, including leases, or of using the contractor's own technology, except for costs for which a transfer pricing study has been prepared in accordance with applicable law.

c. Cap on Cost Recovery

For each month during a term, cost reimbursements to a contractor may not exceed a pre-agreed percentage of the contractual value of hydrocarbons produced during such month. This cap on cost recovery will make it possible for the state to commence receiving overriding royalties from a contractor early in the production period of a contract.   

  1. Recovery Structure

Under a profit sharing contract, a contractor pays the state delay rentals and overriding royalties in cash and delivers to a third party marketer hired by the state all the production from a contract area. The marketer then sells the production and delivers to FMP the proceeds of such sale. FMP retains the state's share in accordance with applicable law and pays the contractor its operating profit share and recoverable costs.

Under a production sharing contract, each month during a term the contractor may retain production in amounts sufficient to pay it recoverable costs (essentially cost oil) incurred during such period and its corresponding share of operating profits. It will also pay FMP delay rentals in cash and deliver to a marketer the state's share of operating profits and royalties payable to it.

Any costs that are not paid to the contractor as a result of the application of the cap are carried-over to subsequent periods for reimbursement, subject to the application of caps during such periods.  

  1. Taxes

A contractor under a production or profit sharing contract will be subject to the payment of the E&P tax, and income and other taxes in the same manner as a licensee will pay such taxes under a license.

Service Contracts

Under a service contract, a contractor provides E&P services in exchange for the payment of a fee payable in cash. Contractors deliver 100% percent of the production from a contract area to a marketer for subsequent sale and remittance of proceeds to FMP. From such proceeds, FMP will pay the contractor its service fee. 

Selected Issues in E&P Contracts

State Participation

To give the state additional options regarding the manner of exploring for and producing hydrocarbons, SENER has the discretion to require state participation in certain E&P projects, and must require state participation in others. In any such cases, state participation will be achieved by requiring that Pemex or any other state company or specialized financial vehicle becomes a party to the E&P contract.

SENER will have the ability to require state participation in virtually any E&P project, though the Hydrocarbons Law limits such discretion to the following specific events:

  • when the licensed or contract area under an E&P contract overlaps at a different depth with an area that has been assigned to Pemex or any other state company;
  • when the state determines that there is a need to transfer technology and know-how to Pemex or any other state company; and
  • when the state has decided to implement a specialized financial vehicle to achieve specific economic or revenue related goals.

Discretionary state participation in an E&P contract may not exceed a 30% interest.

State participation will be mandatory when the licensed or contract area being offered up for bid contains hydrocarbons that may extend beyond the country's boundaries. The state will have at least a 20% interest in the corresponding E&P contract.

Assignments/Changes in Control

All E&P contract assignments and corporate changes that result in a change in the control of the licensee or contractor or of the operations under the licensed or contract area require the prior written consent of CNH. In the latter case, to receive CNH's approval, the new contract operator must have the experience and possess the technical and financial capabilities required to perform the licensee's or contractor's activities in a licensed or contract area, as applicable, and assume all of the E&P obligations under the contract. SENER will also have the ability to block a change in control.

Any corporate change that does not result in a change in the control of a licensee or contractor will only require notice to CNH. 

Rescission

E&P Contracts are administrative contracts under applicable law. This means that the state will have the ability to administratively rescind an E&P contract for stated cases, such as when a contractor fails to perform a minimum exploration program without justification, or a licensee or contractor assigns an E&P contract without consent or fails to comply with a federal court order. The state will also have the ability to rescind a contract if a "serious accident" causing property damage, death or loss of production occurs as the result of a licensee's or contractor's ordinary negligence.

To rescind a contract, the state must send notice thereof to the licensee or contractor, give the licensee or contractor an opportunity to challenge the rescission or cure the cause, and in any event, justify its action by final order. Once the state issues a final order rescinding an E&P contract, the licensee or contractor will have the obligation to transfer the contract area back to the state, without compensation or indemnity payment, and to pay damages, if applicable.

The administrative rescission of an E&P contract is not subject to arbitration.

Booking Reserves

Licensees and contractors may report, for accounting and financial purposes, their respective E&P contracts and the benefits expected therefrom, provided that in each case the contract states that all solid, liquid and gaseous hydrocarbons under the ground are the property of the nation. The Comisión Nacional Bancaria y de Valores, a governmental authority akin to the SEC, will have authority to issue administrative regulations for the booking of reserves. 

Surface Use

Should an E&P contract affect a pre-existing mining concessionaire's use of the surface in the contract area, the parties will have a 90-day period in which to negotiate a mutually agreeable contract that governs each of the parties' use of the surface for operations and the compensation to be paid to the concessionaire as a result of the affectation. Compensation may be in the form of cash, a participation in the extraction of hydrocarbons or both, but under no circumstance may the concessionaire obtain a right in and to the production from the contract area. If the parties do not reach an agreement with respect to such matters, CNH will intervene and determine whether the concessionaire's use of the surface is being affected or not, and if so, if both activities (i.e., E&P of hydrocarbons and mining) may coexist. If such an affectation is determined to exist and the activities may coexist, CNH will determine the amount of compensation payable to the concessionaire, and if the affectation is serious, CNH may direct the licensee or contractor to pay the concessionaire, on an ongoing basis, an amount equal to 0.5% of the licensee's or contractor's profit after all the applicable payments under the E&P contract have been made to the state.

National Content

While each E&P contract will contain tailored provisions relating to national content, all E&P contracts granted in Mexico, excluding those for deep waters or ultra-deep waters, must by the year 2025 contain on an aggregate basis at least 35% of national content. The initial aggregate level for national content in all E&P contracts is 25%.

The national content structure in each E&P contract will be progressive. This means that the various percentages of national content set forth in each contract, will increase in accordance with the expiration of pre-determined periods of time or contract stages.

The Secretaría de Economía, Mexico's ministry of economy, will issue regulations establishing methodologies for the calculation of national content in E&P contracts and will have the authority to audit, whether directly or through a third party auditor, compliance with the percentages established in the contracts. Variables to measure national content will focus on the origin of goods and services used in operations, the use of local and qualified labor, the training of local laborers, the licensee's or contractor's investment commitments with respect to local and regional infrastructure and the transfer of technology.