Fracking findings: Not just what, but who
The presentation of the technical committee’s first recommendations on the feasibility of exploring Mexico’s shale basins through fracking was notable not only for the findings themselves, but for who presented them.
The committee, formally the Scientific Committee on Energy Sovereignty and Unconventional Natural Gas Deposits, delivered its first conclusions at Sheinbaum’s morning press conference on 6 August. Made up of 54 researchers, the majority academics, the panel’s verdict was broadly favourable from an investors’ perspective: it recommended proceeding with hydraulic fracturing in the Sabinas-Burro-Picachos basin (Coahuila/Nuevo León) and the Burgos basin in north-eastern Tamaulipas, subject to ten conditions. Among the most significant: using only saline water for fracturing, which would require drilling wells first to confirm availability; confirming the existence of reserves before scaling up; applying best practice in waste management; carrying out free, prior and informed consultations; and setting up independent, external scientific monitoring.
Sheinbaum was quick to stress that no decision to authorise exploitation had been taken, and that this stage amounted to evaluation only. Even so, the direction of travel looked clear: SENER already has a plan to cut gas imports from 75% of consumption to 50.5% by 2030, with national conventional production rising to 49.5% of demand, against prospective unconventional resources estimated at 141.5 trillion cubic feet in total. Of that, the committee’s own figures put 53.8 tcf in Burgos, 67.0 tcf in Sabinas-Burro-Picachos, and 20.7 tcf in Tampico-Misantla, the smallest of the three but the one being taken off the table entirely.
One of the people steering the group’s work was Alma América Porres Luna, commissioner of the National Hydrocarbons Commission (CNH) from 2010-2022, 10 years as Exploration and Production head of the Instituto Mexicano de Petroleo., with a PhD in Applied Geophysics in the University of Bordeaux, and, without doubt, one of the leading authorities on Mexico’s hydrocarbons sector over the last two decades. Formally, she was one of three coordinators of the committee’s engineering group, alongside Ana Paulina Gómora Figueroa and Erick Emanuel Luna Rojero.
A source inside the group says her presence on the committee was not initially welcomed by all of the 54 researchers involved, ostensibly because she might have been the only invited expert not formally representing a public educational institution or government body, despite her unrivaled qualifications to opine on fracking in Mexico. But for a group leaning heavily towards 4T-inclined academia, several of whose members were openly opposed to fracking, among them UNAM academic Luca Ferrari, a longstanding critic of the technique in Mexico and one of three coordinators of the committee’s planning and prospective group, her experience in the CNH and IMP pre-dating the 4T might have represented an ideological challenge. But despite the initial skepticism, it was Porres who ended up guiding several of the committee’s technical discussions, largely on the strength of her own experience and expertise, which ultimately was welcomed in particular by the members who were specialists in areas such as water and land use, but not in hydrocarbons.
Within a few weeks it became clear the committee needed to move faster, so the group split into subcommittees. As the weeks passed, a handful of no more than five people ended up carrying the workload for the reports that would go to President Sheinbaum.
Porres was leading several of these efforts, and in the meetings held to finalise the presentation to the president, she was asked to deliver the initial findings herself. There were a couple of slides she reportedly asked to have removed, since they referred to successes at Pemex’s Ixachi and Quesqui fields, when it was Porres who, as commissioner, had criticised and voted against Pemex’s proposals for their accelerated development. Time appears to have proven her right: at Ixachi, production has come in slower than Pemex promised, at the cost of flaring large volumes of gas for lack of infrastructure to capture it, while at Quesqui the reservoir was drained rapidly, also with heavy flaring, and the field is now declining fast because of poor planning.
Her efforts thus helped win support for potential fracking in the Sabinas-Burro-Picachos basin (Coahuila/Nuevo León) and the Burgos basin in north-eastern Tamaulipas. Even so, little could be done to secure support for exploration in the Tampico-Misantla basin, Mexico’s largest in unconventional oil reserves, though its smallest in unconventional gas. Sheinbaum, in announcing the exclusion, cited the basin’s location beneath a densely populated area with a high concentration of indigenous communities and ample freshwater reserves. Part of Porres’s contribution behind the scenes was to head off a blanket ban on hydrocarbon activity across the wider Tampico-Misantla zone, where Pemex already produces gas and oil using conventional fracturing techniques, on a much smaller scale than what is understood as shale fracking.
The panel’s brief went beyond fracking specifically: Sheinbaum had originally commissioned it to weigh how far unconventional gas could reduce Mexico’s reliance on natural gas piped in from US shale deposits. The committee’s conclusion was that raising conventional gas output alone would only bring that dependence down to 50.5%, and that closing the remaining gap would require Mexico to pursue unconventional extraction “in a responsible manner,” in Sheinbaum’s words.
What the public presentation omitted, however, was any discussion of the economic and contractual terms needed to actually develop the Burgos and Sabinas-Burro-Picachos basins. In the run-up to the presentation, discussions with the president centred on framing this opening as a response to the risks of gas import dependence, which meant the commercial terms were left on the back burner, nominally within the remit of the planning and prospective group that never produced a workable proposal on this front.
Without those economic and contractual terms, the recommendations remain something of an orphan for now, though some preliminary work can still begin, since Mexico is in any case far from the point where such terms would need to be spelled out. The immediate priority is understanding the resources in these basins: wells are needed to map their geology in more detail, to identify saline water zones suitable for exploitation, and to find areas where crude accompanies the gas, since extracting gas alone rarely makes for a viable project anywhere in the world.
Plenty of questions remain, but the fact that the government is now willing to hear from people who, under the last administration, were dismissed as opponents of the regime and of national sovereignty suggests there may be room to stop these resources being trapped between the subsoil and nationalist ideology.
What still has to be resolved, and what will really determine whether any of this moves beyond paper, is who provides the capital; under what contract; under what fiscal regime; and how the risk is structured. Pemex has neither the technology, the financial capacity nor the experience to run a fracking programme at scale. The companies that do, the operators active in the Permian and Eagle Ford in Texas, need contractual terms that let them move quickly, drill thousands of wells, and book reserves to raise financing. None of that currently exists in Mexico’s regulatory framework. The trust vehicle, the fiscal regime and the contractual structure are the pieces still missing. Without them, the scientific verdict is necessary, but insufficient.
In any case, Mexico’s dependence on abundant, low-cost U.S. gas may prove an even bigger obstacle to developing domestic shale resources than geology or regulation. Mexico is connected to the United States through an extensive cross-border pipeline network, and U.S. pipeline exports to Mexico averaged 6.4 Bcf/d in 2024, compared with total Mexican gas consumption of about 8.6 Bcf/d. Much of that supply comes from Texas, giving Mexican consumers access to some of the cheapest gas in the world.
The economics are particularly difficult to compete with in the Permian Basin, where a large share of natural gas is produced as a by-product of oil production. For those producers, drilling decisions are driven primarily by oil economics rather than by the gas price itself. The Permian also benefits from a mature oilfield-services industry, extensive infrastructure and decades of shale operating experience. Current EIA projections envisage U.S. natural-gas production remaining robust, and potentially continuing to grow, well into the 2040s.
Mexico starts from a very different position. Even if exploration proves successful, new domestic production would have to compete with inexpensive pipeline gas arriving from just across the border. That matters well beyond the upstream industry: natural gas is a key fuel for Mexican power generation and an important input into industrial competitiveness. CFE’s own results illustrate the sensitivity as the company has reported material swings in generation costs and profitability as imported U.S. gas prices rise and fall.
Trying to solve that problem by making imported gas artificially more expensive would therefore be politically and economically difficult. A tariff on qualifying U.S.-origin natural gas would also be hard to reconcile with Mexico’s USMCA commitments, which generally provide duty-free treatment for originating goods. In practice, Mexico faces an awkward policy dilemma: cheap U.S. gas benefits electricity consumers, industry and CFE, but the same cheap supply makes it considerably harder to justify the capital required to develop domestic shale gas.
The refining paradox: more capacity, more imports
A recent analysis by OilPrice.com puts into perspective the central contradiction in Pemex’s self-sufficiency strategy: installed refining capacity has grown, with more than USD 20 billion invested in Dos Bocas alone, yet fuel imports are rising again because the system cannot sustain high utilisation rates.
Pemex’s own figures broadly bear this out. Refined product output (petrol, diesel, jet fuel, fuel oil, LPG and other products combined) averaged around 1.09 million bpd across April to June 2026, against the roughly 1.75 million bpd of installed capacity the analysis cites, consistent with utilisation somewhere in the high-50s to low-60s per cent. This is refined output, not crude throughput: Pemex’s public data does not separate the two, so the comparison is necessarily approximate.
On imports, Pemex’s trade tables confirm the trend. Total refined-product imports averaged around 514,000 bpd across January to May 2026, rising to 638,000 bpd in June. Within June’s total, Pemex reports petrol imports of 377,000 bpd and diesel imports of 121,000 bpd.
There has been genuine progress, as noted in the analysis: Tula improved utilisation from 66% to 79% thanks to its new coker; combined production of petrol, diesel and jet fuel rose 9% year-on-year to 699,000 bpd; and fuel oil yield fell from 22.7% to 18.9%. Pemex is extracting better products from every barrel it processes. What it cannot do is keep enough crude flowing through the refineries. The analysis concludes that Mexico “pays twice for self-sufficiency, once for the capacity it builds, and again for the imported fuels it still needs when that capacity falls short.”
On the export side, the near-term picture is more encouraging. Pemex reported 565,000 bpd in June, its biggest jump in eight years, with four consecutive months of revenue above USD 1 billion. But the rig count fell from 32 to 17 in the second quarter, the lowest level in years, an early indicator of pressure on future production.
Braskem Idesa files for Chapter 11
Braskem Idesa (BI), the Mexican petrochemicals joint venture 75% owned by Brazil’s Braskem and 25% by Carlos Slim’s Inbursa via its control of Idesa, filed for pre-packaged Chapter 11 protection in the US this week, seeking to restructure a balance sheet rendered unsustainable by years of feedstock shortages, weak petrochemical margins and increasingly acute liquidity constraints. The bankruptcy of BI marks a rare reversal (so far) for Carlos Slim, who through Inbursa also owns an important stake in BI’s bonds and debt that have fallen in value since his purchases, and likely has also lost money so far in its broader controlling investment in Idesa.
Under a plan agreed with major creditors, Braskem Idesa aims to cut senior debt by more than $920mn, from about $2.5bn to roughly $1.6bn. Braskem, which owns 75 per cent of the company before the restructuring, has committed $476mn and is expected to remain the majority shareholder. The company says operations at the Etileno XXI complex in Nanchital, Veracruz, will continue during the proceedings, with the eventual goal of restoring production towards its annual capacity of just over 1mn tonnes of polyethylene.
The roots of the crisis lie partly in a feedstock arrangement that ceased to reflect the realities of Mexico’s energy sector. Under a 2010 contract, Pemex committed to supply 66,000 barrels a day of ethane for 20 years, at prices linked to international benchmarks, providing the foundation for the project’s economics. But the state oil company struggled to sustain those volumes as domestic ethane availability declined due in the part to the fall in global ethane prices driven by the shale gas revolution.
The contract was amended in 2021, reducing Pemex’s minimum commitment to 30,000 b/d and increasing the price it received and thus what BI paid. The revised obligation was extended to February 2026, after which Braskem Idesa retained only a right of first refusal over surplus Pemex ethane through 2045, with no minimum volume guarantee. By the second quarter of 2026, Pemex deliveries had fallen to an average 11,800 b/d.
The original arrangement had also become politically contentious. Pemex said the contract had generated substantial losses and the López Obrador government repeatedly criticised its terms and the manner in which it was awarded, linking the contract to the Odebrecht (Braskem’s then co-parent) corruption scandal. The 2021 renegotiation settled outstanding disputes, changed both volume and pricing terms and paved the way for Braskem Idesa to develop an alternative source of feedstock.
Braskem Idesa responded by reducing its dependence on Pemex. It first developed a “fast-track” system to import US ethane and later, with infrastructure group Advario, built Terminal Química Puerto México at Laguna de Pajaritos. Completed in 2025, the terminal can import as much as 80,000 b/d, equivalent to about 120 per cent of Etileno XXI’s needs at full capacity, and is connected to the complex by pipeline. The project’s latest disclosed estimated cost was about $586mn, including $408mn financed through syndicated project debt.
The terminal largely solved the physical availability problem, but not the economics. Imported ethane brings additional shipping, terminal and logistics costs. More importantly, the plant has been caught in a prolonged squeeze in the spread between the polyethylene it sells and the ethane it consumes.
Braskem’s North American benchmark PE-ethane spread fell 19 per cent in 2025. The deterioration reflected weaker polyethylene pricing as new global capacity came on stream, combined with higher feedstock costs. That spread is central to Etileno XXI’s economics: the plant converts ethane into ethylene and then polyethylene, so profitability depends less on the absolute ethane price than on the margin between feedstock and resin.
The spread improved in the first three months of 2026, but the recovery was insufficient to repair the balance sheet. Braskem Idesa reported negative recurring EBITDA of $15mn in the quarter, while polyethylene sales fell 37 per cent from the previous quarter.
By then financial distress had itself begun to constrain operations. Plant utilisation fell to 55 per cent in the first quarter as the company reduced ethane imports to preserve liquidity. In the second quarter, imports through the new terminal dropped to 14,700 b/d from 17,800 b/d, while Pemex deliveries fell to 11,800 b/d. Polyethylene sales declined a further 11 per cent quarter on quarter.
Braskem Idesa had spent hundreds of millions of dollars building infrastructure capable of eliminating its feedstock bottleneck, but deteriorating liquidity left it unable to purchase enough ethane to make full use of that capacity.
The company had already missed scheduled interest payments on its senior secured notes due in 2029 and 2032. Court materials attribute the filing to a combination of compressed petrochemical spreads, the fall in Pemex ethane supply and the higher fixed and variable costs associated with imported feedstock. They also show a supplier base of more than 400 vendors with payments averaging about 150 days past due, while constrained working capital had pushed average utilisation below 50 per cent.
Shareholders and lenders had provided emergency funding ahead of the filing, but this proved insufficient to stabilise operations. Under the Chapter 11 plan, Braskem Idesa is seeking roughly $409mn of debtor-in-possession financing from Braskem affiliates. About $279mn represents new money, including an initial $230mn available under the interim court order, while roughly $130mn refinances emergency bridge facilities extended before the filing.
The aim is not merely to finance the bankruptcy process but to restore working capital and lift production. Creditors are expected to receive a combination of new secured debt and equity, while Braskem will inject fresh capital and retain control of the reorganised company.
Chapter 11 therefore addresses part of Braskem Idesa’s problem. Lower debt and the new import terminal should remove two important constraints: excessive leverage and dependence on Pemex. But Etileno XXI’s longer-term viability will still depend on whether the plant can return to high utilisation rates and whether polyethylene-ethane margins recover enough to turn additional output into cash rather than simply volume. But given the plant is one of the lowest producers in the world, once and if the cycle turns, it is in a strong position to benefit. At that point, maybe Carlos Slim perhaps will eventually recover the value of his investments.
Fuel subsidies subside
For the week of 8–14 August, the SHCP (Finance Ministry) applied one of its sharpest cuts in months: Premium petrol’s subsidy fell from 26.49% to just 5.77% (the lowest since May), Magna dropped 15.56 percentage points, and the IEPS levy rose by more than one peso per litre on both fuels. The adjustment responded to a temporary dip in international prices and to an attempt to recover tax revenue. It was the reverse of July’s moves (when subsidies spiked because of volatility in oil markets related to the Strait of Hormuz).
This week, 15–21 August, the government cut further still, and went a step beyond: it withdrew the Premium subsidy entirely. From Saturday 15 August, the SHCP set the Magna subsidy at 1.10 pesos per litre, down 30 centavos on the week before; eliminated the Premium subsidy altogether, down from 33 centavos; and, in the opposite direction, raised the diesel subsidy by 31 centavos to 5.09 pesos per litre. As a result, motorists paid higher IEPS on both petrol grades and lower IEPS on diesel.
International crude prices increased over the week by as much as 6%, with Brent closing Friday at USD 88.52 a barrel amid a lack of progress on a US-Iran peace deal. Shipping traffic through the Strait of Hormuz fell below its monthly average over the same week, and two tankers belonging to Abu Dhabi’s national oil company were attacked while transiting the strait.
Despite the shifting subsidies and international volatility, retail prices in Mexico held steady over the week: the national average for Magna stood at 23.69 pesos per litre on Friday 14 August, unchanged from the previous week, according to PETROIntelligence; Premium and diesel sold at 28.52 and 27.03 pesos per litre respectively, also unchanged.
End of a majors era
Alberto de la Fuente Piñeirua, president and director-general of Shell México since July 2012, has left the company after two decades to take up the role of SVP Commercial & Business Services at Harbour Energy in Mexico.
De la Fuente was the public face of Shell’s bet on the 2013–2014 energy reform: he drove the firm’s participation in deep-water bidding rounds and in the retail petrol market, and became one of the most influential voices in the private energy sector as president of AMEXHI (2016–2020, 2024–2025) and of the Consejo de Empresas Globales (2021–2023). An economist from ITAM with master’s degrees from Oxford and the Australian Graduate School of Business, before Shell he worked at SENER, the CRE and the Office of the President.
His departure marks, symbolically, the retreat of the big international oil companies that bet on the Peña Nieto-era opening of the sector. Shell had been steadily scaling back its presence in Mexican upstream operations as the regulatory environment tightened under AMLO’s nationalist energy policies. De la Fuente’s move to Harbour Energy, operator of the Zama field and of Block 30, where Slim has just bought TotalEnergies’ stake, signals where private-sector activity in Mexican oil is now concentrated: mid-sized companies holding contracts inherited from the bidding rounds.
Chatter Box
CFE International’s corruption case survives its first major test. A federal court in Houston has rejected a bid by former CFE International executives Guillermo Turrent Schnaas and Javier Gutiérrez Becerril for summary judgment in the corruption lawsuit brought against them by the company in 2022. CFE International alleges that between 2012 and 2018 the executives improperly favoured Texas-based WhiteWater Midstream in natural gas contracts, including the so-called West Texas Agreements covering up to 1 Bcf/d for 15 years from 2019. The company claims the arrangements caused the CFE group economic damages of at least hundreds of millions of dollars and is seeking recovery of compensation paid to the former executives as well as exemplary damages.
The 10 August ruling does not establish that corruption occurred, but it removes an important route for the defendants to dispose of the case before trial. Judge Lee H. Rosenthal rejected their argument that CFE International could not have suffered direct economic harm because it operated effectively as a cost centre for its parent. The litigation will therefore continue towards consideration of the underlying allegations, keeping scrutiny on how CFE International negotiated some of its largest US gas arrangements during the previous decade, and how Whitewater benefited.
Pemex and CFE are being told to show their homework. The federal government is imposing broader disclosure requirements on Pemex, CFE and their subsidiaries as part of a new decree requiring monthly publication of federal government contracts. The rules extend beyond procurement: financial statements, management reports, corporate documents and domestic and international contracts involving the state energy companies will also have to be made public once approved by their boards. According to Anticorruption Secretary Raquel Buenrostro, officials will no longer have broad discretion to withhold information, with exceptions principally limited to national security and ongoing judicial or administrative proceedings.
The significance will depend on implementation. Pemex and CFE sit at the centre of some of Mexico’s largest infrastructure, fuel and electricity transactions, while their new legal status and expanding investment programmes make visibility over contracts increasingly important. Moving towards monthly disclosure, and potentially including information linked to foreign filings, audits and operating policies, could provide considerably more visibility into how the companies spend and contract. The real test will be how broadly the permitted exceptions are interpreted and whether the new digital platform delivers information that is timely and sufficiently detailed to allow meaningful scrutiny.
La Esperanza gives CFE another route into private renewables. Construction has begun on La Esperanza Solar in Escárcega, Campeche, a 420 MW photovoltaic project paired with a 150 MW/750 MWh battery system being developed by Copenhagen Infrastructure Partners’ Growth Markets Fund II. The project reached financial close with approximately USD 510 million in debt from an international banking consortium, alongside equity from CIP and Mexican pension fund Profuturo. CFE Calificados is participating through a long-term power contract that provides the project with demand certainty while adding renewable electricity to CFE’s supply portfolio.
The structure is notable because CFE does not need to develop or own the plant to expand the amount of renewable power it can commercialise. Instead, the private developer carries the investment and development burden while CFE Calificados provides the long-term offtake that helps make financing possible. The five-hour battery is particularly relevant for the Yucatán Peninsula, where growing demand and grid constraints make dispatchable renewable supply more valuable than solar generation alone. Alongside CFE’s own projects and the government’s new mixed-investment framework, La Esperanza illustrates another channel through which private capital can still contribute to Mexico’s renewable build-out.
Sheinbaum cooling on data centres? President Sheinbaum pushed back against the idea that Mexico should position itself as an AI hosting hub for the rest of the world, considering how much water and energy they require, at her 18 August press conference. However, she acknowledged data centres are necessary for Mexico to advance in AI development.
Responding to an AFP question citing hours-long blackouts in Querétaro and companies reportedly warning that demand is outstripping supply, Sheinbaum asked her team to pull CFE’s daily outage report for her to review. CFE’s recent data about outages in the region, covered in our last edition, reports they fell 39% in H1 2026 versus H1 2024, though absolute figures and updated SAIDI/SAIFI indicators are still outstanding. Querétaro is home to 72% of Mexico’s installed data-centre capacity, and these facilities currently draw 200–300 MW, a figure that could climb to 1,300 MW in the short to medium term.
On the underlying grid strain, Sheinbaum blamed summer temperatures and AC use, and pointed to some regions needing transmission and distribution investment more than new generation. Her fix: 28,000 MW of planned new capacity, split between renewables and combined-cycle gas, plus a new 54% public/46% private investment scheme meant to attract outside capital while keeping the state in majority control.
She further clarified that although data centres are being built, the country’s economic growth should not depend on them; instead, they should be located where they are needed and developed through strategic planning, alongside other manufacturing investments.
BP changes the guard in Mexico. Angélica Ruiz Celis has left BP after eight years with the company, stepping down both as president of BP Mexico and senior vice-president for Latin America. Pedro Elío, a BP veteran with previous experience at Shell, InterGen and First Solar, will take over the Mexican operation, while David Campbell assumes regional responsibility for Latin America. Ruiz, one of the more visible executives in Mexico’s energy industry, says she intends to remain involved in the sector through independent board positions and strategic projects.
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