Regional Report: Gulf Of America/Gulf of Mexico

GORDON FELLER, Contributing Editor 

Fig. 1. The Gulf continues to be the primary U.S. offshore source of oil and gas, generating about 97% of all OCS oil and gas production. Image: Bureau of Ocean Energy Management.

Hydrocarbon exploration and production (E&P) projects in the Gulf of America/Gulf of Mexico (the Gulf) have been influenced by a range of external factors over the past year. Significant changes to the external environment, including political, economic and financial conditions, are affecting hydrocarbon projects in ways that could not have been predicted during 2024.  

Such significant “externalities” make for a challenging environment for Gulf hydrocarbon projects. These are necessitating adaptive strategies from those wishing to sustain both profitability and operational efficiency. Externalities are reshaping the operational landscape for both private companies and state-owned enterprises like Pemex, but they’re also creating opportunities for those taking risks in this region’s energy sector. 

Political developments play a pivotal role in shaping the Gulf’s hydrocarbon industry. In Mexico, the government pursues policies that prioritize strengthening Pemex’s role in the energy sector while limiting private-sector involvement. This has included halting new contract allocation rounds for exploration areas, effectively reducing opportunities for private companies to expand their operations in Mexican waters. While this strategy aligns with the government’s goal of reinforcing state control over energy resources, it has constrained foreign investment and innovation, which are vital for advancing complex projects such as deepwater developments. 

Fig. 2. Woodside’s floating production platform that will operate offshore Mexico in Trion field, in the Gulf. Image: Woodside Energy.

In contrast, U.S. political conditions have remained relatively stable, with federal agencies like the Bureau of Ocean Energy Management (BOEM) continuing to support deepwater operations through regulatory approvals and resource management frameworks, Fig. 1. However, cross-border energy cooperation between the U.S. and Mexico now faces challenges, due to the Trump administration’s dramatic shift away from free trade policies. Furthermore, Mexico’s focus on state-led initiatives now stands in stark contrast with the U.S.’s market-driven approach, complicating everything from joint ventures to resource-sharing agreements. 

Global economic trends are also exerting their own influence on hydrocarbon projects in the Gulf of America/Gulf of Mexico. Oil price volatility has been a major factor, with fluctuating prices impacting project economics. High-cost deepwater projects, such as Mexico’s Trion field (Fig. 2) or Shell’s Whale project in U.S. waters, are particularly sensitive to these changes. While oil prices rebounded slightly in late 2024, due to geopolitical tensions and supply disruptions, operators are now extremely cautious about long-term price stability. 

Inflationary pressures have also affected operational costs across the region. Rising prices for materials and services have increased capital expenditure requirements for new developments and maintenance activities. For example, Pemex’s Lakach natural gas project required additional investments of over $400 million to update its production strategy and infrastructure. These cost escalations are forcing otherwise enthusiastic operators to reassess budgets and timelines for their major projects. 

Fig. 3. Mexican President Claudia Sheinbaum. Image: Bloomberg.

Financial challenges have been particularly acute for Pemex, Mexico’s state oil company, which is grappling with severe economic strains. In 2024, Pemex reported an annual loss of approximately $30 billion, marking its third consecutive year of negative performance. The company faces declining production levels—crude output has fallen to its lowest point since 1979—and operational inefficiencies at its refineries. Compounding these issues is Pemex’s staggering debt burden of nearly $100 billion, which includes $20 billion owed to oilfield service providers. 

Despite these setbacks, Pemex continues to receive substantial financial support from the Mexican government. A new legislative framework introduced by President Claudia Sheinbaum (Fig. 3) aims to revitalize Pemex by enabling profit-sharing agreements with private-sector partners for joint ventures that could account for up to 10% of its production. This policy seeks to attract private investment while ensuring that Pemex retains control over key assets. Whether these measures will be sufficient to stabilize the company remains uncertain. 

In the U.S., financial conditions have been more favorable for private operators in the Gulf. Companies like Chevron and Shell have successfully launched new deepwater projects, using advanced technologies, such as 20,000-psi-rated equipment for high-pressure reservoirs. These innovations are helping to mitigate risks associated with volatile oil prices and operational costs, which in turn helps to improve the prospects for profitability —even under challenging market conditions. 

For state-owned entities like Pemex, improving operational efficiency and fostering international partnerships will be critical for long-term sustainability. Meanwhile, private companies must continue leveraging innovation to navigate economic uncertainties while maximizing returns on investment in deepwater operations. As the geopolitical turmoil resulting from Trump’s tariff moves continues, and as global energy demand shifts in sometimes unpredictable ways, Gulf hydrocarbon projects face pressures that could throw the region off balance for years to come. 

Policy changes have a profound impact on the economic viability of deepwater hydrocarbon projects in the Gulf. These projects, which require significant upfront investment and advanced technology, are highly sensitive to shifts in regulatory frameworks, permitting processes and government incentives. While certain policies can enhance project economics by reducing costs or incentivizing development, others can create delays, increase compliance expenses, or discourage long-term investment. Understanding how these policy changes affect deepwater operations is critical for stakeholders navigating this complex and capital-intensive industry. 

One way that policy changes influence deepwater project viability is through adjustments to royalty rates and discount parameters. For example, the U.S. Bureau of Ocean Energy Management (BOEM) has introduced policies allowing companies to self-report discount rates for certain deepwater projects that require advanced technologies, such as enhanced flow assurance technologies (EFAT). These policies aim to balance private-sector profitability with government revenue interests by ensuring that marginal resources are developed rather than stranded.

Fig. 4. A summary and map of all current U.S. Gulf leasing. Image: U.S. Bureau of Ocean Energy Management.

An important example here is BOEM’s proposal to cap discount rates at 20% for extended-reach tie-backs—projects that connect new wells to existing infrastructure over long distances. These tie-backs often rely on expensive technologies like subsea booster pumps and advanced flow assurance systems. By allowing operators to use higher discount rates when calculating project economics, the policy reduces the financial barriers for these technically challenging developments. Such measures lower breakeven oil prices for deepwater projects, making them more viable, even in volatile market conditions. 

Permitting delays and regulatory uncertainty are among the most significant ways that policy changes can undermine the economic viability of deepwater projects. Delays in obtaining drilling permits or abrupt changes in regulatory frameworks can inflate costs and disrupt project timelines. For instance, a 2024 study by Wood Mackenzie found that a one-year permitting delay could render 13 out of 25 analyzed deepwater Gulf projects uneconomic, risking the loss of approximately 540,000 barrels of oil equivalent per day (boed) in production. A two-year delay would affect even more projects, potentially jeopardizing 680,000 boed of future output. A summary and map of all current U.S. Gulf leasing is in Fig. 4.  

Historical examples illustrate the economic risks associated with permitting delays. Following the Deepwater Horizon oil spill in 2010, the U.S. government imposed a moratorium on deepwater drilling. This policy caused immediate disruptions, as operators were forced to halt ongoing projects. ATP Oil & Gas, for instance, had to abandon a low-risk gas development in the Mississippi Canyon, due to prolonged permit delays, leading to significant financial losses and missed economic opportunities. 

Such delays not only increase capital expenditures but also reduce investor confidence in the regulatory environment. For operators working on tight margins, even minor disruptions can make an otherwise profitable project economically unfeasible. 

Stricter safety and environmental regulations are also playing a key role in shaping Gulf project economics. Following the Deepwater Horizon disaster, new regulations were introduced to improve safety standards and mitigate environmental risks. While these measures are essential for reducing liabilities and protecting ecosystems, they come with substantial costs. 

A study by the U.S.-based nonprofit Resources for the Future (RFF) estimated that stricter safety standards could raise exploration and production costs by 10% to 20%. For example, regulations requiring advanced blowout preventers or high-pressure equipment rated for 20,000 psi significantly increase upfront capital expenditures. While these technologies are necessary for accessing ultra-deep reservoirs safely, they add financial burdens that disproportionately affect marginal fields with slim profit margins. 

The cumulative effect of these compliance costs is a reduction in overall production potential. According to RFF’s analysis, a 20% increase in costs could lead to an 8% decline in U.S. offshore production by 2035. In extreme scenarios—such as a complete ban on new offshore drilling—production could drop by as much as 79%, severely impacting energy security and regional economies. 

Shifts in political priorities also influence deepwater project viability by altering long-term investment strategies. Pro-drilling policies streamline permitting processes and/or reduce royalty rates—all with an eye towards encouraging development by lowering costs and improving returns on investment. For instance, initiatives like the Heritage Foundation’s infamous “Project 2025” aim to expand offshore drilling opportunities while reducing regulatory hurdles. However, such policies often face public backlash, due to the widely held view that these “corporate welfare” giveaways ignore critical issues (such as environmental concerns), thereby creating reputational risks for operators. 

Conversely, anti-drilling policies—such as proposals to ban new offshore leases—can have severe economic consequences. In the U.S. Gulf’s Eastern region alone, such restrictions could strand an estimated 4.5 Bboe near existing infrastructure. This would not only limit future production but also reduce the utilization rates of existing facilities, many of which already operate below 50% capacity, due to underinvestment in new tie-back projects. 

Political uncertainty further complicates long-term planning for operators. When governments frequently change their stance on offshore drilling policies, companies are less likely to commit capital to multi-decade projects that require stable regulatory environments. 

Policy-driven subsidies or penalties also intersect with global market dynamics to influence project economics. For example, shallow-water projects generally face fewer regulatory hurdles but yield smaller reserves compared to deepwater developments. Policies that incentivize deepwater exploration—such as tax credits or subsidies for advanced technologies—are critical for justifying their higher complexity and cost structures. 

Cross-border disparities further highlight the role of policy in shaping economic outcomes. In Mexico, state-centric energy policies prioritize Pemex over private-sector involvement, limiting opportunities for foreign investment in deepwater fields like Trion or Zama. In contrast, U.S. policies typically favor market-driven approaches that encourage private investment but still face challenges from environmental opposition. 

Policy changes profoundly impact the economic viability of deepwater projects by influencing costs, timelines and investment incentives. Adjustments to royalty rates and discount parameters will enhance profitability by reducing financial barriers for marginal developments. However, permitting delays and regulatory uncertainty inflate costs and deter long-term investment. Stricter compliance requirements improve safety but add significant financial burdens that disproportionately affect high-cost fields. 

Fig. 5. Oil production in the U.S. Gulf dropped 4.5% during 2024. Image: Shell.

Ultimately, the balance between supportive policies and regulatory oversight determines whether deepwater projects remain economically viable in an increasingly competitive energy landscape. Operators must navigate these challenges through adaptive strategies, such as leveraging advanced technologies and fostering collaboration with policymakers to ensure sustainable development while meeting energy demands effectively. 

To better understand the past 12 months, and to look ahead, we asked for insights from two of the experts at Wood Mackenzie: Principal Analyst Mfon Usoro, and Research Analyst James Blackwood. Here is a summary of their views: 

The Gulf of America/Gulf of Mexico reached several significant milestones in 2024: “Chevron's Anchor field commenced production, unlocking the ultra-high-pressure (20k-psi) Inboard Paleogene play. bp sanctioned the Kaskida project, continuing the trend of 20k-psi project approvals.” 

M&A activity picked up, as deal spending increased to over $2 billion: “Talos acquired QuarterNorth for $1.3 billion, and INEOS also entered the region by purchasing CNOOC's assets which Wood Mackenzie values at $1.8 billion.” 

The biggest threat to operations in the region “came from a court case involving the Biological Opinion (BiOp). The BiOp governs Endangered Species Act compliance for Gulf permitting. Environmental groups challenged the validity of the current BiOp, and the court granted a stay until May 2025, allowing operations to continue as normal while a new Biological Opinion is prepared.” 

As regards 2024 production/exploration in comparison to 2023: “Oil production in the Gulf of America/Gulf of Mexico (Fig. 5) dropped slightly to 1.75 MMbpd in 2024, 4.5% lower than 2023. Project delays and an active hurricane season drove the decline.” 

Exploration activity slowed down “as operators prioritized development activity to boost cash flow. Operators drilled only 14 exploration wells, the lowest in ten years. This resulted in the lowest volume of new discovered resources in 25 years.” 

Their key 2025 predictions are notable: “Liquids production is expected to grow to 2.2 MMbpd, and the region will join Brazil as the second deepwater region to surpass 2 MMbpd. Operators have already done much of the requisite drilling and completion work to unlock 2025 liquids growth. Select greenfield and brownfield developments will underpin the liquids growth.” 

Their assessment is that “exploration will pick up slightly, compared to 2024, with over 20 wells planned. The Independents will underpin exploration activity rebound.” 

The Trump administration has pro-energy posturing, which means regulatory risks for the region will be lower: “The new government aims to create a supportive environment for E&Ps, but this won’t directly alter capital spending for 2025. Companies will invest around $11 billion in the region, with about $1.6 billion in ultra-high-pressure projects. But this increase isn't necessarily due to new policies and deregulation but rather reflects the current position of most operators in their investment cycles.” 

As regards the potential impacts of the new U.S./Mexico trade war: Their view is that it “won't directly affect deepwater oil production in the Gulf of America/Gulf of Mexico. But it could impact broader energy trade in North America. There are concerns about steel tariffs, as it could increase costs for materials and supplies needed in offshore projects and erode returns, adding to uncertainty.” 

For another point of view, we consulted with EY, the global consulting and accounting firm. Our first discussion was with Greg Matlock, who serves as both EY Americas Oil, Gas, and Chemicals Industry Tax Leader and as EY Americas Mining and Metals Industry Tax Leader. He pointed us to the EIA’s latest outlook, which estimates that 2025 production in the Gulf “will exceed 2024 production, although not by much. We’re likely to see an increased focus on capital discipline, due in part to some of the uncertainty around tariff impacts and a renewed focus on shareholder returns that ought to result in a prioritization of high-return investments, certain of which are in the Gulf.”    

Matlock’s mindful of the fact that “significant blue hydrogen and ammonia-related projects are also underway on the Gulf Coast, with the geographic-advantaged location of the feedstock and offtake and a similar positive outlook for liquefied natural gas (LNG) projects. Many of which now have significant governmental support.”  

Matlock notes that carbon capture-related projects, including the direct tie into upstream production, as well as oil-and-gas-related assets, “continue to move in earnest.”  

Finally, tax policy, “including policies to extend prior tax cuts, could certainly aid in the deployment of additional capital in the region.”   

Bruce On, EY’s Strategy and Transactions Energy Partner, brings a different lens to the discussion. In general, he’s concluded that “there’s continued interest and activity in the Gulf, driven by the advantaged nature of those assets. As the current administration streamlines the regulatory environment, we’ll likely see activity growth in the U.S. and in the Gulf.”    

One of the determining factors will be commodity prices “and whether the current market volatility slows down the pace of M&A. With the recent focus on tariffs and how they can impact global economies, fluctuating commodity prices will be challenging for companies to finalize development plans and M&A activity.”  

Fig. 6. Map of the development layout for Zama field, offshore Mexico. Image: Wintershall Dea.

That being said, On “knows the Gulf assets are longer-term plays, and we’d expect to see continued investment in that space, given the cost structure efficiencies being gained through technology advancement. From an M&A lens, outside of the Permian, the Gulf is an area that has a lot of interest with its return profile and proven economics.”  

Regarding carbon capture and storage (CCS), On assesses that “there’s continued investment going into CCS assets and the focus on the connection between upstream production will continue to grow. However, synergistic opportunities that are positive for the industry and for companies must make sense for those investments to take place in 2025.” 

LEADING GULF PROJECTS SHOW SIGNIFICANT ATTRIBUTES

Each of the Gulf of America/Gulf of Mexico’s leading hydrocarbon E&P projects are notable, both for their size and ambition, as this list illustrates. 

Zama field. Located in the Sureste basin, Zama is a shallow-water field discovered by Talos Energy in 2017 and now operated by Pemex in partnership with international firms, Fig. 6. It holds recoverable reserves of 625.68 Mboe and 243.29 billion Bcf of gas. The project features advanced infrastructure, including Octapode-type platforms and subsea pipelines. Production is set to begin in December 2025, targeting 180,000 bopd by 2029. Total development costs are estimated at $4.5 billion, with a similar amount allocated for operations and decommissioning. The project will include 29 production wells and 17 water injection wells to optimize recovery. Doris Group, the French engineering firm, is managing the front-end engineering design (FEED). Zama is expected to operate until 2053, and will undoubtedly play a critical role in Mexico’ energy future. 

Trion project. Situated in the Perdido Fold Belt, Trion is Mexico’s first ultra-deepwater oil development. Operated by Woodside Energy with Pemex as a partner, it will utilize floating production and storage units (FPSUs). The project will drill 12 wells and connect to the South Texas-Tuxpan pipeline for gas transport. Estimated peak production is 100,000 bopd and 124 MMcfd of gas by 2035. Total investment is projected at $10.43 billion, with $7 billion allocated for capital expenditure. 

Hokchi field. Located in the Salina del Istmo basin, this shallow-water field is operated by Hokchi Energy. Current production is approximately 27,000 boed, with plans to increase to 37,000 boed. Infrastructure includes two offshore platforms linked to an onshore processing facility. The project has projected a lifespan investment of $2.5 billion. 

Mad Dog Phase 2 (Argos Platform). Operated by bp, this deepwater project focuses on high-pressure reservoirs in the Paleogene play. The Argos platform began operations recently as part of a $9 billion investment. It employs advanced technology for subsurface analysis and enhanced recovery. 

Gettysburg field. Owned and operated by Kosmos Energy, this field lies in the U.S. Gulf's Central Planning Area. Production is expected to start in 2025 with a peak output of 40,000 boed by 2028. 

North Platte field. A deepwater project operated by TotalEnergies, North Platte focuses on high-pressure reservoirs. It represents significant advancements in drilling technology for enhanced recovery. 

Kaskida project. Operated by bp, Kaskida is part of bp’s Paleogene strategy focusing on maximizing value around existing hubs. The project will leverage new subsurface analytics and cost-reduction measures. 

Tiber field. Another bp-operated Paleogene play, Tiber aims to unlock high-temperature reservoirs using cutting-edge technology. 

Guadalupe project. As an important part of bp’s portfolio, Guadalupe focuses on optimizing production near existing infrastructure hubs. 

Perdido hub. Operated by Shell, Perdido is one of the deepest offshore platforms globally. It focuses on ultra-deepwater fields like Great White and Tobago.