Nearly one year ago Mexico's government enacted a ground-breaking constitutional reform wrapping over the country's entire energy sector. Since then, President Enrique Peña Nieto has signed 21 secondary laws defining the anatomy of the reform.
Round Zero provides Pemex with access to 12.45 billion of Mexico's proven oil reserves, leaving foreign oil companies with access to 60 fields, covering 3.78 billion barrels of proven reserve during Round One, which will open private tendering next year.
With rapidly declining oil production and an ailing state-owned oil and gas company (Pemex), reforms have been necessary, but not many believed that they would go as far as they did (not even me — read my predictions from last year). After 76 years of oil nationalism, Mexico is opening the door for foreign and private investors to exploit its black gold.
Foreign companies were only able to operate in the country under service agreements up until now, but the fiscal regime will allow new exploration and production contract models including profit sharing, production sharing and license contracts. Further, a simplification of the fiscal regime, tax incentives and reductions could lead to expected savings of 36 percent of Pemex's tax and royalty payments.
As follows, I will provide a quick overview of the guts of the new fiscal regime awaiting foreign and private investors next year.
Basically, the new regime is two-fold collecting a corporate income tax of 30 percent plus a set of taxes and fees varying depending on whether extraction and exploration is conducted under (1) so-called "asignaciones" (assignments) that are only granted to Pemex or a "state productive company," or (2) contracts signed with Pemex in association with private entities or with private entities on their own.
Under the assignment regime, state-owned companies pay three different types of federal fees: a shared profit fee, a hydrocarbons extraction fee and a hydrocarbon exploration fee. The hydrocarbons extraction fee is determined in a similar way to the royalty payments charged under the contractual regime, with fees varying on a sliding scale depending on the type of hydrocarbon and international price.
The hydrocarbon exploration fee (or surface rental fee) will be charged on a monthly basis depending on the surface area under exploration — incentivizing companies to fulfill their exploration plans within a specified time frame. The shared profit fee applies to the value of extracted hydrocarbons during the corresponding fiscal year (including consumption of these by the assignment holder, spillage and flaring) minus deductions. The fee will initially amount to 70 percent in FY2015 and decrease to 65 percent by FY2019.
With respect to the contractual regime, there will be four different contract types — license, production sharing, profit sharing and service contracts. There will be different types of taxes for different types of contracts (except for service contracts).
Licence contracts will charge a contract signing bonus, royalties, an exploration phase tax and a compensation on the value of hydrocarbons. Profit sharing and production sharing contracts will charge royalties, exploration phase tax and a compensation on net operation profit.
Royalty rates are determined on a sliding scale basis varying according to the type of field, its production level and the international price of oil and gas (similar to the hydrocarbon extraction fee under the assignment regime). Royalties will go up if production or prices move above a certain threshold, and the exact amount will only be published in the signed contract.
Companies will also have to pay an exploration phase tax determined similar to the hydrocarbon exploration fee under the assignment regime.
Profit sharing and product sharing contract will pay a compensation based on their net operational profits (the value of hydrocarbons extracted minus royalties and cost deductions), which will be defined in the signed contract. Licensors, on the other hand, will provide a compensation based on the value of hydrocarbons they produce.
There also a number of investment incentives — such as a royalty discount for shale gas. Moreover, while cost deductions will usually be capped at $6.50 for each barrel of oil produced and at 12.5 percent of oil revenues for onshore and shallow water assignments, there will be a cap of 60 percent of oil revenues for deep water production and for the Chicontepe field, currently operated by Pemex. There will also be a cost deduction cap of 80 percent of revenues from the production of gas and condensate revenue.
Compared to the previous fiscal regime under which Pemex had to pay a corporate income tax plus 10 additional taxes, the new system will be much simpler and allow for a profit share for foreign oil and gas companies.
Despite these fiscal overhaul, the benefits still have to materialize, and there are outstanding questions — such as who is going to pay for Pemex's enormous outstanding costs for labor and social responsibilities for its 15,000 employees, which is an estimated $127 billion.
The government has offered to assume one third of the liabilities, under the condition that Pemex negotiates with the oil workers' union to raise the retirement age from 55 to 65 years. Unions must agree that the pension fund will be audited and the currently defined benefit plan will also have to be changed toward defined contributions on an individual basis.
