PEMEX Cancels Four Mixed Contracts, Modifies Framework

PEMEX has officially cancelled four highly valued mixed contracts, Nobilis-Maximiliano, Kayab-Pit-Utsil, Macuil-Paki, and Tlatitok-Sejkan, citing force majeure due to compressed timelines. Together representing over 2,100MMb of 3P reserves, these projects had drawn major interest from global giants like Shell, Eni, BP, Woodside, and SLB. However, deep-seated structural issues and rigid regulatory terms, such as the absence of direct agreement mechanisms, strict tax requirements, and limited private operational control, prevented the finalization of the bids. PEMEX and private developers are currently negotiating critical modifications to the mixed contract framework. The cancellations represent a serious setback to the Sheinbaum administration's national target of maintaining 1.8MMb/d of production by 2030, particularly as PEMEX's own capital expenditure in exploration and extraction dropped by 51% in early 2026.

PEMEX has cancelled four mixed contracts that had been suspended since late 2025, citing force majeure associated with insufficient timelines to address concerns raised by participating companies. The four cancelled contracts, Nobilis-Maximiliano, Kayab-Pit-Utsil, Macuil-Paki, and Tlatitok-Sejkan, together represent more than 2,100MMb of 3P reserves. Of those, Kayab-Pit-Utsil and Macuil-Paki alone concentrate 400MMb of proven 1P reserves with a 90% recovery probability. First-year guarantees on the four contracts had reached US$175 million.

The contracts had attracted the interest of Shell, Eni, BP, Woodside, and SLB, five of the largest upstream operators and service companies globally, within the mixed contract scheme before the processes were suspended. PEMEX is working alongside private companies on adjustments to the mixed contracts, with the objective of incentivizing greater investment in the hydrocarbons sector.

The four fields span Mexico's most strategically significant offshore geographies. Nobilis-Maximiliano is located deepwater off Tamaulipas, in the Paleogene-era formation that shares its geological characteristics with the US side of the Gulf, where BP and Shell have each committed billions to development. Kayab-Pit-Utsil is positioned off the coast of Campeche, the basin at the heart of Mexico's legacy production. Macuil-Paki and Tlatitok-Sejkan are shallow water Tabasco fields with documented proven reserves.

Kayab-Pit-Utsil alone has a surface area of 128km2 and stands as the highest-volume contract, with 822MMb of crude oil and almost 95Bcf of natural gas. Of the five wells PEMEX had drilled in the area, 70 additional wells were being solicited for the new development stage. Tlatitok-Sejkan holds 40MMb of crude oil.

The Force Majeure Rationale and What It Obscures

The force majeure classification is a legal mechanism that allows cancellation without penalty to either party. The companies that had engaged with these four processes represent a cross-section of the international oil industry's most technically capable deepwater and offshore operators, and their documented concerns about the mixed contract framework have been well established in prior reporting: the absence of mechanisms for direct agreements leaving banks without explicit rights over physical assets, legal ambiguity around contract breaches and PPA preservation rights, and permit portability concerns when PEMEX retains majority control but a private partner has invested in development.

That pattern of private capital declining to follow signed commitments into execution is not unique to these four contracts. In May, Carlos Slim, Chairman, Grupo Carso, declared the Lakach deepwater gas field technically and financially irrational, confirming that his company never deployed capital or began operations despite signing a formal contract with PEMEX. Grupo Carso had signed a Comprehensive Exploration and Extraction Service Contract for Lakach in July 2024, committing to an investment program of US$1.88 billion, yet Slim's exit marked the third collapse of a partnership to develop the field, following an earlier PEMEX suspension in 2016 and the 2023 breakdown of a deal with New Fortress Energy. Slim's stated logic was comparative economics: he argued that four onshore wells at the Ixachi field could match Lakach's output at a fraction of the complexity and cost. The recurring theme across Lakach and the four now-cancelled mixed contracts is the same: private partners with capital and technical capacity are willing to sign, and in some cases to conduct due diligence, but are proving reluctant to commit funds once the underlying commercial and legal terms are scrutinized in detail.

The Framework Adjustment Under Development

PEMEX working with private companies on contract modifications is the most concrete signal yet that the original mixed contract terms were not commercially viable for the international operators the scheme was designed to attract. Javier Estrada, an energy specialist, stated that private companies and PEMEX are in a process of dialogue to modify these contracts. "Private companies demand greater payment certainty, operational capacity, and efficiency-based benefits, so it should be evaluated whether oil reserves can be linked to the project, not as the property of the applicant, but as part of the asset where investment is needed, as is done in other countries to make them attractive," he told Reforma.

The mixed contract mechanism itself was introduced as part of a broader 2025 legislative overhaul. According to Rocío Abreu, President of the Energy Commission, Mexico's Chamber of Deputies, Congress enacted 11 laws, including eight new and three amended statutes, to provide clear rules and support strategic alliances for the energy sector, among them reforms that reduced PEMEX's overall tax burden from levels above 50% to a flat 30%. Abreu also confirmed that new mixed contracts with private companies were being introduced to support exploration, mature field development, and unconventional projects, while contracts signed under previous frameworks would continue to be respected.

These contracts allow PEMEX to develop oil fields without spending public resources: private parties contribute 100% of capital investment and operating expenses and assume the financial risk of the project, while the state company retains a minimum 40% share of net revenues. That structure, more favorable to private operators than the 54% minimum CFE retains in the electricity sector, was nevertheless insufficient to close execution with Shell, Eni, BP, Woodside, and SLB on four of the highest-value fields in the portfolio.

The broader services ecosystem underscores why capital discipline has become the default posture for companies weighing new PEMEX commitments. Payment delays tied to Mexico's production decline have forced providers to rework capital exposure, and Halliburton has flagged international revenue pressure linked in part to lower activity in Mexico, noting that unresolved supplier payment timing has curtailed operations even as decline rates heighten the need for service reactivation. As one Halliburton executive put it, the lack of payments causes capital to shift away from the country toward emerging markets that compete with Mexico. Providers have responded by leaning toward performance-based milestones and shared-risk financing structures rather than front-loaded capital cycles, a dynamic that mirrors the caution now surfacing among the operators PEMEX is trying to bring back to the negotiating table for Nobilis-Maximiliano, Kayab-Pit-Utsil, Macuil-Paki, and Tlatitok-Sejkan.

The Production and Reserves Implications

PEMEX's current production sits at approximately 1.65MMb/d, against an administration target of 1.8MMb/d by 2030. Moody's has warned that stabilization at current levels reflects execution improvements rather than a structural reversal of decline, with major producing fields declining at underlying rates in the low 20% range on a production-weighted basis. The reserves backdrop reinforces the stakes involved. PEMEX's proven, or 1P, reserves have fallen approximately 40% over the past eleven years, from 12.4 billion barrels of oil equivalent in 2014 to 7.471 billion at the close of 2025, according to the company's most recent filing with the US Securities and Exchange Commission. While the 2025 reserve replacement rate reached 102.6%, indicating a modest post-2018 stabilization rather than continued collapse, the incremental additions remain small relative to the scale required to reverse the long-run trend. Capital expenditure in the exploration and extraction segment fell 51% in real terms in early 2026, and the active drilling rig count declined from 32 to 25 between January and May, a constraint that narrows PEMEX's room to absorb the loss of four mixed-contract fields without a corresponding adjustment elsewhere in its portfolio.

The cancellation of Kayab-Pit-Utsil and Nobilis-Maximino, two of the highest-volume contracts in the portfolio, reduces the near-term potential of the mixed contract mechanism to contribute meaningfully to the 1.8MMb/d target. A Petrobras memorandum of understanding on deepwater cooperation and the unconventional gas scientific panel's forthcoming recommendations remain the two other upstream mechanisms with meaningful production potential, but neither is expected to generate barrels within PEMEX's remaining window for this administration.