The Future of Mexico’s Production Portfolio

Despite Mexico’s agreement with OPEC+ to cut down production levels, Mexican oil production survived 2020 with only a minor impact. According to CNIH data, production never dipped below 1.6MMb/d, with a nadir of 1.604MMb/d in July 2020, which was the month immediately following the OPEC+ agreement. While production levels have yet to reach the pre-pandemic 1.7MMb/d benchmark, continuous increases since August 2020 indicate that reaching the milestone is only a matter of time.

The government’s insistence on raising production levels clashes with the prevailing uncertainty and discussion that surrounds the question of the future value of oil. All of this raises questions for Mexico regarding where its oil will come from and whether its sourcing will have to respond to a new structure for the national industry and for the global oil and gas market. Diversification will prove to be essential in this process, experts told MBN.

PEMEX, SENER: Opportunities Clash with Ideologies

PEMEX’s flagship fields, such as Ku-Maloob-Zaap, are now categorized as mature. Their faster-than-expected depletion is now considered a certainty by the company’s upstream engineers. These fields were not just reliable in terms of production levels but also in terms of cost per barrel extracted, which remained low thanks to the existing, publicly-owned infrastructure and geological knowledge that supported their operations. 

Besides increasing its production levels, PEMEX’s No. 1 mandate is to reduce its debt, which implies the urgent need to make its production processes and commercialization as efficient as possible. How PEMEX can significantly reduce its debt without reducing its production levels is the dilemma that the NOC finds itself in, according to renowned energy sector analyst Arturo Carranza. “This is what the credit rating agencies are talking about when they say that PEMEX needs to reexamine its business model.” 

Carranza believes that the message that the credit rating agencies are sending is that the NOC cannot meaningfully reduce its debt without greatly reducing its investment program or at least adjusting it so that it is focused on the most profitable segments of the oil and gas industry’s productive value chain. 

The key is in collaborating with the private sector, says Carranza. “This new business model should be focused on the tools that PEMEX gained from the 2014 Energy Reform, instead of ignoring those tools with the strategy that has been adopted since December 2018.” This includes the use of farmouts, associations and alternative contractual models that allow it to share risk with more ease. The prevailing political climate in Mexico shows no indication of changing enough to allow SENER to organize the restarting of bidding rounds. If anything, the attempts in the legislative chambers during 2021 to change the downstream sector’s regulatory framework would suggest the opposite. 

However, SENER has the opportunity to respect these political limits while also finding a way to make some of these contractual tools available to PEMEX without creating unnecessary conflict. This would allow PEMEX to diversify the sourcing of its production levels, especially when considering the steady rhythm of discoveries that the NOC has been making since 2019, such as that of the Quesqui field. 

Otherwise, the only degree of support that SENER will be able to give the NOC will be limited to direct financial support, according to Carranza. “If the NOC’s indicators do not improve significantly in the short to midterm, the governmental financial support it receives could become a money pit that threatens the integrity of public budgeting. It is debatable whether SENER’s transfer of more than US$2.26 billion to PEMEX could have been better spent elsewhere,” he says.  

Nevertheless, Carranza says that PEMEX’s strategy is producing some positive results in the form of increasing crude oil processing at refineries. In 1Q21, production levels of oil products increased 42 percent when compared to 1Q20. “This is a significant increase that highlights the government’s efforts to have a nationally productive industry that can provide energy sovereignty and independence.” 

The question is whether these upward trends in production levels, both upstream and downstream, can be maintained. “Increases in oil production do not always correspond to increases in investment. One could even argue that investments so far have not resulted in the expected amount of production increases.” Carranza also observes that calculating these figures is extremely difficult given the unique situation the oil and gas industry experienced over the last 12 months, but he remains skeptical that PEMEX will be able to maintain a positive growth curve as far as its production metrics are concerned. “Oil demand and prices are likely to continue their recovery, which will increase PEMEX’s income and corresponding financial maneuverability. However, the situation remains too complex for the company to safely continue its course without any significant change in its business model,” says Carranza.  

Private Operators’ Contributions

While production contributions of private operators to national levels have been modest, they have done nothing but rise throughout 2020 and 2021. Hokchi Energy began early production right in the middle of the pandemic by developing a shallow water field originally discovered by PEMEX in 2009 and holding 178.1MMb in total crude. According to AMEXHI Director General Merlin Cochran, the field is likely to produce 15Mb/d to add to overall production figures this year. 

Hokchi’s output can be added to the 25Mb/d that Cochran believes could be produced by Fieldwood and Petrobal at the Ichakil and Pokoch fields by the end of 2021 and Eni’s 22Mb/d from the AMT complex since 2020. These offshore operators have also continued with their exploration activities, incorporating significant volumes of reserves that could be added in the short to midterm to the country’s production portfolio. At the end of 2020, CNH announced that it had approved Eni’s multimillion-dollar exploration plans to extend its search of the Saasken field, a discovery the company said could hold up to 300MMboe.

Onshore operators have also contributed significant production volumes to Mexico’s portfolio. Onshore projects reached productive phases sooner than expected, especially those that began as abandoned PEMEX fields and that were easier to connect to PEMEX’s commercialization infrastructure. Many might not represent the large volumes handled in the shallow waters of the Campeche Basin but their contributions are collectively significant nonetheless, especially due to their relatively lower extraction costs. 

One example is provided by Yann Kirsch, COO of Perseus Energy, who highlights the company’s cleanup activities at the Tajon reservoir, which revealed the reservoir’s great energy and pressure, reaching a production potential of 7,000b/d. “Tajon’s upcoming well remediation has led us to discussions with top oil field services companies to make sure that this process is as successful as possible,” says Kirsch. In Perseus’ other major block, Fortuna Nacional, the production potential has motivated what Kirsch calls “an aggressive drilling campaign.” “We believe that Fortuna Nacional is a field with tremendous potential and a royalty scheme that enables high ROI and profitability. Both Tajon and Fortuna Nacional also have the advantage of interconnectivity to PEMEX’s infrastructure, which allows for an effective commercialization of all produced hydrocarbons.” 

One of the most successful private onshore operators in Mexico has been Jaguar E&P. CEO Warren Levy emphasizes the importance of maximizing onshore production with what is available to operators in this category. “We have focused more on maximizing production in existing fields. During 2020, we reactivated a number of wells. This allowed us to more than double our production. Given that these fields had legacy infrastructure, we are pleased with the result.” 

2021 is a key year for Jaguar to deliver exploration results but also to prepare a development program that is in the permitting process mostly for its acreage in the Burgos Basin. “The goal is to raise production via development wells and additional facilities,” says Levy.

Levy also highlights the importance of onshore gas production as part of Mexico’s hydrocarbon portfolio. “The macro situation makes it clear that a bridge is needed between today and where we need to be tomorrow in regard to clean energy. Increasingly, it looks like this bridge is natural gas. It can help reduce emissions while renewable tech improves.” 

Levy believes that natural gas is also a great feedstock for all areas of the industry’s value chain, including the downstream petrochemical industry, and will be required much longer than conventional power generation. “Mexico spends about US$5 billion a year on imported natural gas. This means that US$0.93 of every US$1 leaves Mexico. If that gas was produced, purchased and consumed in Mexico, the country would retain that US$5 billion,” says Levy. 

Over the next year or so, Levy expects gas prices to be in the high US$2 per MMBTU to the low US$3 per MMBTU. Furthermore, he believes that significant policy changes on both sides of the border will also contribute to the acceleration of a transition. “US President Joe Biden may push forward with emission reductions in the US and that would lead to higher power production via gas. Demand might, therefore, rise faster than expected,” he says. “If the demand for oil is not there, more conventional associated gas will come off the market globally, which will be beneficial for the gas price.”

Oil and Gas Production Amid the Energy Transition

The opportunities created by natural gas production suggest another dilemma when speaking of Mexican production related to the incoming energy transition. Perhaps the operator most involved in this question is PEMEX. Other NOCs and also IOCs of comparable size and global importance, such as Shell and BP, are already transitioning toward a business model that phases out fossil fuels to address the climate crisis. This has already had an impact on Mexico, as Equinor’s divestment from its Mexican deepwater assets demonstrated, which took place as a direct response to that company’s energy transition mandates. 

PEMEX needs to define how it will face this process, as well, states Niels Versfeld, CEO of Simmons Edeco. “Publicly traded oil and gas companies, especially the supermajors, have been under increasing pressure to not just reduce emissions but to stop investment in oil and gas all together.” Versfeld points to the International Energy Agency (IEA) calling for the end of all investment in oil and gas projects immediately as the writing is on the wall, along with the case of Exxonmobil, not considered a climate leader, being forced by an activist hedge fund to bring on board additional climate-focused directors. Even Shell, considered a climate leader, did not escape a Dutch courts’ decision that legally forced the company to reduce greenhouse gas emissions more aggressively.

The fact that oil and gas production will remain relevant to the government’s energy objectives and to Mexico’s interest as a whole will have to be balanced with all of these developments, keeping in mind expectations regarding ongoing oil and gas demand. The IEA itself predicts that oil and gas demand will continue to increase even if renewable power generation grows faster than current forecasts. As Versfeld highlights: “In an optimistic scenario wherein the developed world was to stop oil and gas consumption and switch to renewables by 2050, is it plausible to think that all countries, especially those that have not had the benefits of energy-rich development, will stop consuming fossil fuels?”