Regional Report: Gulf Of America/Mexico

GORDON FELLER, Contributing Editor 

Fig. 1. The U.S. Gulf has 1,958 active leases, comprising 29,100 blocks. Map: U.S. EIA.

The U.S./Israeli war with Iran has turned the world’s energy systems upside down: increasing costs at levels for all actors, from upstream to downstream; disrupting global trade flows; spiking gas and oil prices – all of it forcing major producers and consumers to scramble to adapt. The war has also turned the world’s focus toward stable environs, like the Gulf of America/Mexico (GOA/M or U.S. Gulf), as everyone seeks out stable and reliable sources of supply. 

THE U.S. GULF MAKES A COMEBACK 

Energy industry historians will look back at 2026 for many reasons. One will be the industry-wide reassessment of the GOA/M, Fig. 1. The Middle East’s current conflagration – with munitions of various types exploding in at least 11 countries or territories, so far—is radically shifting risk perceptions for Middle Eastern oil and gas. This means that some other places, like the GOA/M, benefit from the shifting tides. 

The Russian attack on Ukraine in 2022 turned U.S.-origin LNG from a promising business into a strategic lifeline for Europe, as sanctions and sabotage choked off Russian pipeline gas. That reliance deepened, when Iranian‑linked drone strikes forced Qatar and neighboring exporters to suspend LNG loadings in early 2026, sending global spot prices sharply higher.  

Fig. 2. Big Beautiful Gulf 1 lease sale in December 2025 received $300.4 million in high bids. Map: U.S. EIA.

Yet the price spike was notably less severe than it might have been a decade earlier, precisely because U.S. Gulf exports had expanded to fill such a large share of the market. “Today, thanks to the boom in U.S. LNG exports, the world economy has a shock absorber,” noted The Wall Street Journal. 

Renewed lease sales. The Trump administration’s timing was not bad: In December 2025, in describing the first Big Beautiful Gulf 1 lease sale (Fig. 2), the U.S. Department of the Interior said the "sale generated $300,425,222 in high bids for 181 blocks across 80 million acres in federal waters of the Gulf of America. Thirty companies submitted 219 bids totaling $371,881,093." (https://www.doi.gov/pressreleases/energy-dominance-first-lease-sale-one-big). 

When the Big Beautiful Gulf 2 lease sale was announced by Interior’s Bureau of Ocean Energy Management in March 2026, Secretary Doug Burgum noted that this second non-discretionary offshore oil and gas lease sale "included 25 blocks covering approximately 141,000 acres in federal waters of the Gulf of America, Fig. 3. Thirteen companies submitted 38 bids totaling $69,838,782.” (https://www.doi.gov/pressreleases/interior-holds-second-lease-sale-gulf-america-under-one-big-beautiful-bill-act). 

Fig. 3. Big Beautiful Gulf 2 lease sale in March 2026 received $69.8 million in bids. Map: U.S. EIA.

The LNG factor. The new perceptions of the U.S. Gulf were not always like this. In 2016, when Cheniere Energy began to export LNG from the Gulf, there was much doubt from nay-sayers. After the Russian attack on Ukraine in 2022, and after Iran's attacks on Oman and Qatar in 2026, the company's very large bets began paying off in big ways for both the supplier and a growing list of desperate customers. But this is only one part of the U.S. Gulf's story of the past 12 months, which has been defined by surging offshore production, frantic midstream build‑out to the U.S. Gulf Coast, and a widening strategic partnership—and tension—between the U.S. and Mexico over managing the Gulf.  

When Cheniere converted Sabine Pass from an import terminal into an export hub and sent out the first lower‑48 LNG cargo in early 2016, it was still a contrarian wager that U.S. gas would be cheap and plentiful for decades. A decade and nearly 5,000 cargoes later, the company has become the largest U.S. LNG producer and a linchpin of global gas trade, anchoring a chain of liquefaction plants stretching along the Gulf Coast from Texas to Louisiana, Fig. 4.  

Fig. 4. Ten years of U.S. LNG exports, plus two years of forecasted levels. Chart: U.S. EIA.

That industrial arch has turned the GOA/M into what some call “the firewall of the Atlantic gas market,” buffering Europe and parts of Asia from geopolitical shocks that would once have sent prices into double‑digit panic. The U.S. Gulf Coast has become the world’s emergency supplier of last resort.  

U.S. Gulf output picture. Over the last year, the basic production story has been this: offshore volumes in the U.S. Gulf have stopped being the slowly‑declining legacy they once were and are edging higher, even as most new North American drilling happens onshore. At the same time, almost all new gas transport capacity has been designed to funnel molecules toward the Gulf Coast export corridor, not into markets in the Midwest or Northeast.  

The U.S. Energy Information Administration (EIA) estimates that crude output in the GOA/M averaged around 1.8 MMbpd to 1.9 MMbpd in 2023–2024 and is poised to grow further, as a wave of new deepwater projects ramps up through 2025 and 2026. Associated gas production from these new fields is projected to rise as well, adding roughly 90 MMcfd in 2025 and 270 MMcfd in 2026, keeping offshore gas volumes broadly flat to slightly higher, despite natural decline.  

Fig. 5. LLOG’s (now Harbour Energy’s) Salamanca facility went onstream in late September 2025. Image: LLOG/Harbour Energy.

Regulators have expected operators to start production at about a dozen new GOA/M fields during 2025–2026, most of them deepwater developments tied back to existing floating production units. Eight of these projects are subsea tie-backs, while five involve four brand‑new floating production units, including LLOG’s Salamanca facility, which is handling output from two separate fields, Fig. 5.  

The U.S. Bureau of Ocean Energy Management (BOEM) notes that deepwater wells already account for nearly 94% of the Gulf’s crude oil production and about 80% of its natural gas output, a concentration that is only rising as shallow‑water infrastructure ages out. There are fewer but much larger projects, run by companies with the balance sheets and technical capacity to handle 20,000‑psi (20K psi) reservoirs and multi‑billion‑dollar developments.  

Enverus Intelligence Research concluded that deepwater GOM production can be sustained at nearly 2 MMbopd through the end of the decade, provided operators successfully apply multi-stage hydraulic fracturing techniques to unlock remaining reserves in the Lower Tertiary play. This is a technology that Enverus identified as critical to the basin's long-term production outlook. 

Fig. 6. Chevron’s Anchor field, which began production in August 2024, uses specialized, multi-billion-dollar infrastructure to manage extreme pressures. Image: Chevron.

The GOA/M trend, also seen in the wider world of deepwater oil and gas, is that major energy companies are concentrating capital on fewer, high-stakes, ultra-deepwater developments capable of withstanding pressures of 20K psi. This shift, driven by major operators like Chevron and bp, enables the extraction of billions of barrels of previously inaccessible, high-pressure, high-temperature reserves. Companies see opportunities, which is why they’re enthusiastically moving beyond the previous 15,000-psi limit to access Lower Tertiary and other deepwater formations.  

The trend is dominated by large-scale projects, such as Chevron’s Anchor field (started 2024), which uses specialized, multi-billion-dollar infrastructure to manage extreme pressures, Fig. 6. Other major projects include bp's Kaskida, Fig. 7. These projects require specialized equipment—such as 8th-generation drillships and 20K blowout preventers (BOPs)—that only a few companies have the capital and technical expertise to deploy. Operators are prioritizing high-return, long-term offshore projects over smaller, faster-return projects to generate "far superior economics" and maintain financial resilience. 

Industry and government forecasts now depict the Gulf as a modest growth engine for U.S. oil supply in the mid‑2020s. The EIA projects that GOA/M oil output ticked up by about 100,000 bpd in 2025, reaching close to 1.9 MMbpd, and could rise toward 2.0 MMbpd during 2026, as new fields hit peak rates. 

Fig. 7. The Kaskida field development operated by bp should go onstream in 2029. Image: bp.

Even with this oil resurgence, the center of gravity in the U.S. Gulf story has clearly shifted toward LNG and gas infrastructure. The Gulf is rapidly evolving from an oil‑dominated offshore basin to a broader energy corridor, where LNG exports and, increasingly, offshore renewables anchor long‑term capital deployment.  

Analysts at S&P Global Commodity Insights estimate that U.S. LNG export capacity is on track to roughly double between 2025 and 2029, surpassing 180 million metric tons per year as new Gulf Coast liquefaction trains enter service. The world is re‑plumbing itself around the U.S. Gulf Coast; most of the required feed gas will come from the Permian basin, Haynesville shale, and Eagle Ford shale via new and expanded pipelines terminating at GOA/M export terminals.  

Economists emphasize the Gulf’s role in supporting U.S. upstream and midstream employment while keeping domestic gas prices relatively moderate by absorbing surplus supply. Without exports, Henry Hub would be languishing at uneconomic levels for producers—and, as a result, we’d see more financial stress in the shale patch.  

Technology helps out. A less visible but crucial trend of the past 12 months has been the maturation of ultra‑high‑pressure deepwater drilling technology. New subsea equipment capable of operating safely at pressures up to 20,000 psi has opened previously unreachable reservoirs, dramatically expanding the recoverable resource base.  

Companies like Chevron and bp have started production or taken final investment decisions on projects that rely on this new generation of hardware, such as we’re seeing on the ground in Chevron’s Anchor development and BP’s Tiber, and in related fields. Chevron has emphasized that the region contains some of its highest‑margin barrels. The firm adds that high‑pressure drilling technology allows them to access new depths and unlock resources that were once unreachable. Theoretically, up to 5 Bbbl of crude could be unlocked, over time.  

Fig. 8. U.S. gas pipeline projects completed in 2025 alone added about 6.3 Bcfd of new capacity, and roughly 85% of that was built to move gas toward the Gulf Coast, either directly into LNG terminals or into nearby hubs. Map: U.S. EIA.

Midstream trends out of deepwater fields. If deepwater platforms are the Gulf’s cathedrals, the pipelines and compression stations feeding the coast are its capillaries. Over the last 12 months, the midstream sector has quietly laid the groundwork for another phase of export growth. U.S. gas pipeline projects completed in 2025 alone added about 6.3 Bcfd of new capacity, and roughly 85% of that was built to move gas toward the Gulf Coast, either directly into LNG terminals or into nearby hubs, Fig. 8.  

The days of fighting to build gas pipes into New England are over. Every incremental dollar of capital wants to go south—to the Gulf—to chase LNG netbacks. That view is echoed in the latest EIA projections, which show U.S. Gulf‑bound pipeline flows increasing faster than any other regional corridor in the country through the late 2020s.  

Another wave of gas pipeline expansions targeting the U.S. Gulf Coast is already in motion, with project dockets at the Federal Energy Regulatory Commission dominated by GOA/M‑bound proposals. Some midstream executives are now predicting that, by this time next year, industry leaders will be talking about constraints at the docks, not on the pipes; the bottleneck is shifting from the wellhead to the ship channel.  

Cost factors. Despite the technological breakthroughs and strong price environment, not every GOA/M oil project is getting the green light. Industry executives and insurers speaking at marine and energy conferences in 2025 stressed that long‑cycle offshore developments must compete with faster‑payback shale projects and, increasingly, with LNG and renewables for capital.  

S&P Global analysts point out that deepwater projects in emerging basins like Guyana and Brazil often offer lower breakeven costs than U.S. Gulf prospects, drawing some investment away from the region. The Gulf remains attractive, but it is no longer the only game in town. Companies are cherry‑picking only the very best prospects. 

The most significant forward‑looking trend is the race to add new liquefaction capacity along the Gulf Coast before the end of the decade. S&P Global’s projection that U.S. LNG capacity will roughly double by 2029 implies a steady drumbeat of final investment decisions and construction milestones over the next 12 to 24 months.  

In practical terms, that means multiple new trains at existing sites—as well as entirely new terminals—will be competing for labor, steel, and shipping slots along the Gulf between now and 2027. Some U.S.-based LNG project financiers believe that cost inflation and permitting timelines will be the key constraints, not the availability of gas. We’re entering a period of intense competition for engineering and construction resources on the Gulf Coast. Travis Woods, president of Coast Industrial Group, has noted that contractors raised wages for skilled workers by as much as 20% in three years, and in some cases are having to pay a per diem rate to retain them, adding: "Welders and pipefitters are being offered up to $60 an hour and a sign-on bonus, if they agree to stay through completion."  

McKinsey published an analysis which it put it this way: "LNG projects are competing with other large-scale projects (such as petrochemicals and renewables) for the same limited pools of local skills, suppliers and contractors, driving up construction wages, per diems, and risking productivity declines." 

Demand‑side risks remain. European gas consumption is trending lower, as efficiency gains and renewables bite, and Asian buyers are wary of over‑contracting after a bruising price cycle. Still, the shock of the Iranian attacks on Persian Gulf shipping has reinforced the perceived value of diversified, politically stable supply from U.S. shores, giving GOA/M LNG developers a strong narrative, as they court new long‑term buyers.  

SITUATION OFFSHORE MEXICO  

On the southern side of the Gulf, Mexico’s energy approach has been more cautious—and more political. While the country has discovered sizeable offshore reserves in recent years, particularly in the shallow‑water Sureste basin, capital deployment has lagged behind that of the U.S. side.  

Mexican experts often point to the policy legacy of “energy sovereignty,” which has prioritized state oil company Pemex over foreign partners. The GOA/M could be Mexico’s economic engine for decades, but they are under‑investing, especially in gas infrastructure that could connect to the U.S. LNG machine just across the water. At the same time, Mexico’s government is acutely aware of the environmental and social concerns that have accompanied the U.S. Gulf boom.  

For Mexico, the next 12 months may prove decisive in determining whether it becomes a more active partner in the Gulf’s gas and LNG story or remains largely a spectator. Federal policymakers sitting in Mexico City are under pressure to address chronic gas shortages in the southeast and high industrial power prices, problems that could be eased by better integration with U.S. Gulf gas flows.  

Some Mexican experts advocate for targeted reforms to allow more private participation in offshore gas development and cross‑border infrastructure, arguing that “energy security doesn’t stop at the maritime border; it’s a regional project.” Others warn that aligning too closely with U.S. LNG interests could undercut Mexico’s own decarbonization goals and entrench dependence on fossil fuels. Which vision prevails will shape not only Mexico’s economy but also the longer‑term political stability of Gulf energy cooperation.  

Fig. 9. The Trion field production unit is shown under construction during 2025. Image: Woodside Energy.

It’s notable that S&P Global Commodity Insights reported that roughly 70% of the deepwater blocks auctioned in the Mexican portion of the Gulf during 2015–2017 had been returned by private companies. Operators including Shell, Chevron, CNOOC, Repsol, and Petronas had relinquished their exploration rights, citing insufficient discovered resource volumes relative to the level of investment required. This trend stood in contrast to continued robust activity on the U.S. federal offshore side of the GOA/M. 

Yet, Gulf fields offer up good news. After years of planning, the Trion Deepwater field crossed its most significant operational threshold in early March 2026: drilling has formally begun, making it Mexico's first-ever ultra-deepwater oil development. Construction and engineering have both been progressing. Trion reached 50% overall completion by the end of 2025, with the floating production unit hull assembly completed, the upper column frame erected, and critical topside module equipment installed, Fig. 9.  

Woodside Energy and PEMEX launched drilling operations at Trion Field on March 9, 2026, marking the formal start of Mexico's first ultra-deepwater oil development—an $11 billion program targeting 24 subsea wells and peak production of approximately 100,000 bopd via a dedicated floating production unit. The wells will be drilled by Transocean's Deepwater Thalassa drillship, supported by supply vessels and logistics services operating from ports in the state of Tamaulipas, strengthening local and regional supply chains. The Deepwater Thalassa arrived in Mexican waters on March 5, 2026.  

SLB was awarded a major drilling contract by Woodside for the ultra-deepwater Trion development, with services beginning in early 2026 and managed through SLB's Performance Live digital service delivery centers. Additionally, Tenaris was awarded the supply of casing and tubing for the Trion project, including 12,000 tons of casing and tubing and approximately 16,000 tons of pipe for flowlines and risers. The project remains on schedule and within its approved budget. First oil is expected in 2028, and over the lifetime of the project, Trion is projected to deliver more than $10 billion in taxes and royalties to Mexico. 

The Zama shallow-water field underwent a major governance restructuring—PEMEX ceded the operator role it had held since 2021, with Harbour Energy formally appointed as the new operator at year-end 2025. Three companies entered advanced discussions to operate Zama under a joint operating agreement—Talos Mexico (in which the multi-billionaire Carlos Slim's Grupo Carso is a majority investor), Harbour Energy, and PEMEX. This is a rare model for the state company, one in which PEMEX would cede some control. Harbour Energy was formally appointed operator of the Zama oil development offshore Mexico, following unanimous agreement by project partners PEMEX, Grupo Carso, and Talos Energy, and subsequent approval by Mexico's Ministry of Energy (SENER). The current ownership split is PEMEX at 50.4%, Harbour Energy at 32.22%, and Talos Energy Mexico at 17.35%.  

The new operator has explained that the next step will be to complete engineering and design work in 2026 ahead of a final investment decision (FID). Zama's 30-year production sharing contract is slated to expire in 2049. An FID is now expected in 2026–2027. Zama holds an estimated 750 MMboe in gross recoverable resources and, once onstream, first oil could be achieved within 36 to 48 months post-FID, positioning Zama as a meaningful contributor to production growth by the late 2020s. 

FINAL THOUGHTS 

The GOA/M now sits at the intersection of energy security, climate ambition, and regional geopolitics in a way few could have imagined when Cheniere loaded its first LNG cargo in 2016. Over the past 12 months, the region has proven its ability to deliver more oil and gas, to reroute global trade flows during crises, and to attract enormous capital into deepwater platforms, export terminals, and pipelines.  

The next 12 months will test whether it can do so while maintaining social license at home, managing environmental risk, and sharing the benefits more equitably between the U.S. and Mexico.