For Mexico, constitutional reform was just the first step in the long process of opening up its energy industry to outside investment. Secondary laws must now be passed, and existing laws need to be modified to establish a framework for participation in the industry which, for 75 years, has been the exclusive domain of Petroleos Mexicanos (Pemex).
The degree of private participation will be influenced heavily by the contract models selected by the Mexican government, their fiscal terms, and the prospectivity of reserves open to investment.
“There is going to be a deep transformation in the industry, not just Pemex,” Jordy Herrera, Mexico’s former secretary of energy told Mayer Brown’s Global Energy Conference in Houston.
Included in the package are several laws pertaining to oil and gas exploration and production, such as the proposed Law of Hydrocarbons, the Law of Hydrocarbon Revenues, and the Law of Petroleos Mexicanos (Pemex). The legislation was slated to be debated in a special session of Congress in late June.
“It is up to Congress to determine under what terms and conditions” the private sector has to abide by, Jose Valera, partner in Mayer Brown’s energy practice, told UOGR.
After laws are finalized, existing regulatory agencies must be configured to regulate private sector activity and grant permits. These agencies are accustomed to working exclusively with Pemex.
“It’s a huge job,” Valera said.
Another pending step involves determining for which fields Pemex will hold exclusive development rights. The national oil company in March requested it be allowed to retain 100% of Mexico’s producing areas, 83% of proven and probable reserves, and 31% of prospective hydrocarbon resources.
The Ministry of Energy has until Sept. 17 to decide how much Pemex keeps. “My opinion is it is going to change a little,” Herrera said. He expects Pemex will be allowed to keep about 75% of the country’s known resources, and the remaining 25% will be opened up for competitive bidding.
Likely to end up on the auction block are some deepwater areas and areas prospective to shale development. Herrera said Pemex lacks the funds, technology, and experience to develop all of these challenging areas on its own.
Mayer Brown research suggests that some shallow-water areas, mature fields, and extra-heavy oil fields may also be made available for international bidders.
The Ministry of Energy will ultimately decide which geographic areas to make available for international bidding and when they will be unveiled. The ministry will also be responsible for deciding which contract types will be applied to which areas, evaluating bids, awarding contracts, and later monitoring exploration and production plans to ensure contract compliance and maximize productivity.
Contract models under consideration include production-sharing agreements, profit-sharing agreements, pure service contracts, and licenses but not concessions. For companies considering participation in the the first bid rounds, Valera said, the attractiveness of investment will be determined by the fiscal terms and conditions selected for the new contracts.
Bidding will be overseen by the National Hydrocarbons Commission. Mexico’s government is targeting June 2015 for the first bid round, but Herrera does not expect the first round will occur until after the country’s midterm elections for lower house lawmakers in July 2015.
“There is no official schedule. All of these dates are simply target dates,” Valera told UOGR. The actual date of the bid round is contingent on how fast the country enacts laws and sets up regulatory agencies.
In areas where Pemex is granted exclusive development rights, the company is likely to convert some of its entitlement contracts into risk-sharing upstream contracts with private parties. Separate bid rounds may be held to determine what companies may work with the state-owned entity.
Oversight for that bidding would be managed by the National Hydrocarbons Commission. Technical and contractual guidelines would be established by the Ministry of Energy, and fiscal terms would be determined by the Ministry of Finance.
Impetus for reform
Declining oil and gas production and low reserve replacement rates were the impetus for the historic energy reforms.
Mexico’s production outlook has deteriorated in the past decade as offshore production from the massive Cantarell field decreased and rising output from Ku-Maloob-Zapp and other fields did not offset declines (see figure).
Herrera said the county had appeared poised to become one of the largest oil producers in the world in 2004, when crude production peaked at around 3.4 million b/d. Output has since fallen to about 2.5 million b/d in 2012. Natural gas production has declined from a peak of nearly 8 bcfd to 5.6 bcfd in 2013, and increasing amounts of gas are being imported to meet domestic demand.
The rationale for reform was practical. “There was a realization that Mexico was going to begin losing money with this policy,” Valera told UOGR.
Mexico is now a net importer of natural gas and refined products, bringing in roughly 1.4 bcfd of gas, 80,000 b/d of liquefied petroleum gas, and 400,000 b/d of gasoline.
Delia Maria Paredes Mier, executive director of economic analysis at Mexican bank Grupo Financiero Banorte, said about 20% of domestic gasoline demand is met by imports priced on the international market and sold to Mexican consumers at a discount. The program, now being phased out, is a substantial cost for Pemex.
Meanwhile, production is declining despite increased levels of capital investment as conventional reserves dwindle and unconventional resources prove costly and technically challenging to develop. Mayer Brown research shows that Mexico invested $26 billion in oil and gas in 2013, compared with $4.8 billion in 2001.
“The reforms have opened up a potentially huge pipeline of new investment,” Mier said. But, she added, “it’s going to take some time before we see the first drop of oil” from shale or deepwater fields.