Saudi Aramco Eyes Major Stake in New $11 Billion Indian Refinery

By Charles Kennedy - Dec 30, 2025

Saudi Aramco is poised to buy a 20% stake in a new refinery that India’s state-owned refiner Bharat Petroleum Corporation Limited (BPCL) plans to build with a total investment of about $11 billion, Indian news outlet Business Standard reports. 

BPCL plans to have the refinery built at the Ramayapatnam port in the state of Andhra Pradesh on the east coast of southern India. The refinery is planned to have a processing capacity of between 180,000 and 240,000 barrels per day (bpd).  

The Indian company, which is the country’s second-biggest state refiner with 706,000 bpd of crude processing capacity, plans to sell a 30–40% equity stake to outside investors. This stake would include a 20% interest to Saudi Aramco, a nearly 10% stake to Oil India Ltd (OIL), and another 4–5% equity stake to interested banks, according to a senior BPCL official who spoke to Business Standard.  

Earlier this year, BPCL secured the land for the new refinery. The Andhra Pradesh government allocated 6,000 acres for the refinery and petrochemicals project, which is expected to cost about $11 billion (967 billion Indian rupees). The state government has asked BPCL to launch commercial operations at the refinery by January 2029, per the order cited by Reuters.

Currently, BPCL operates three refineries in India. The company and other Indian refiners are looking to boost their crude processing and petrochemicals capacity to meet growing demand in the world’s third-largest crude oil importer. 

Saudi Arabia, for its part, looks to lock in future term sales for its crude in the top Asian markets, which are set to continue driving global demand growth in the coming years. India has even surpassed China as the single biggest driver of demand growth. 

Sources in India told Reuters earlier this year that Aramco was in discussions to invest in two planned refineries in India. 

Saudi Aramco is discussing buying a stake in the BPCL refining and petrochemical complex in south India, and is in separate talks with Oil and Natural Gas Corporation Limited (ONGC) for a proposed refinery in the Gujarat state on India’s west coast, the sources told Reuters.   

By Charles Kennedy for Oilprice.com

Investor Hesitation Stalls India's Offshore Oil Push

By Julianne Geiger - Dec 30, 2025

India has once again kicked the can down the road on its biggest oil and gas licensing round, extending the deadline for bids under OALP-X to February 18. It is the fourth extension since the round was launched with much fanfare during India Energy Week in February, and it says a lot about the gap between ambition and investor appetite.

OALP-X is not a small offering quietly tucked away in some dark corner of the upstream segment. It is the largest acreage round India has ever put on the table under its Hydrocarbon Exploration and Licensing Policy, covering nearly 192,000 square kilometers across 13 sedimentary basins. The mix is heavily offshore: ultra-deepwater, deepwater, shallow water, and a smaller slice of onshore acreage. In August, New Delhi had already pushed the deadline to October, citing the need to give bidders more time. Then came another extension to December. Now it is February.

Officially, there is no explanation this time around. But unofficially, the reasons are the usual suspects. Investor participation has been lacking, weighed down by regulatory complexity, tax burdens, and lingering uncertainty over drilling rules and fiscal terms. A recent increase in the GST rate on exploration and production inputs did not help, nor did the reality that the government take can reach as much as 60 to 70 percent of upstream revenues.

That is awkward timing for a country that depends on imports for more than 85 percent of its oil and wants that number lower, not higher. India’s crude import dependence hit a record in the last fiscal year, even as demand continues to climb and domestic production stays flat. The government knows this, which is why it has been courting foreign majors and talking up frontier basins like the Andaman offshore, sometimes with Guyana-scale comparisons that raise eyebrows.

There is interest on paper. Petrobras has signed letters of intent with Indian state producers. Exxon, Chevron, BP, and TotalEnergies have all inked cooperation agreements. But interest doesn’t necessarily translate into bids, and bids do not equal rigs in the water.

Repeated deadline extensions are so far managing to keep the round alive, despite signaling hesitation.

By Julianne Geiger for Oilprice.com

Will Saudi Arabia/UAE Tensions Over Yemen Threaten OPEC Status Quo?

By Julianne Geiger - Dec 30, 2025

The latest flare-up between Saudi Arabia and the United Arab Emirates over Yemen looks dramatic on the surface, but OPEC cohesion, not missiles or militias, is what ultimately matters to the oil markets, which is why the latest public spat between Saudi Arabia and the UAE over Yemen created just a temporary blip in crude prices.

Saudi forces intercepted this week what they said was an unauthorized UAE-linked shipment of weapons and military equipment destined for southern Yemen. The Saudi-led coalition dished out an airstrike on the southern Yemeni port of Mukalla after Riyadh framed it as a security breach. Abu Dhabi claimed that the equipment was intended for its own counterterrorism forces and denied that it was arming separatist groups.

In the end, the UAE said it would pull out its remaining forces out of Yemen, according to Reuters.

It is messy, public, and awkward — especially given that Saudi Arabia and the UAE sit at the core of OPEC’s decision-making. Yet for oil markets, the immediate impact is close to zero. And that is precisely because OPEC is not a club held together by shared values, shared foreign policy, or shared views on Yemen

OPEC works because its members can disagree (even loudly) on politics while still coordinating production plans.

We have seen this before, although perhaps not on this scale. Saudi-Emirati tensions over Yemen are not new. Both countries entered the conflict together in 2015, then gradually diverged as their interests in southern Yemen split. Riyadh prioritizes territorial unity and border security. Abu Dhabi has backed southern factions it sees as better aligned with its maritime and security goals. Those differences have simmered for years, and yet they haven’t blown up OPEC policy.

There is precedent to draw on for the oil market. In 2021, the UAE openly threatened to block an OPEC+ deal over production baselines, arguing that its rapidly expanding capacity was being unfairly constrained. A compromise eventually resolved the dispute, but exposed OPEC’s real sticking point: capacity growth versus quota discipline.

That dynamic is far more relevant heading into 2026 than any Yemen-related spat. Next year is already looking like it will be a tense one for OPEC, with forecasts warning of oversupply and softer prices, even as OPEC itself has avoided endorsing the glut narrative. But managing production targets in that environment will require cohesion—harmony over Yemen is not required.

Saudi Arabia’s challenge is not that its partners occasionally clash outside the oil market. It is ensuring that those clashes do not bleed into production policy when restraint matters most. Yemen noise may test diplomatic bandwidth, but history suggests that OPEC can function perfectly well without everyone holding hands, as long as they still agree on the math.

By Julianne Geiger for Oilprice.com

Why Saudi Arabia Just Moved Into Syria’s Oil And Gas Fields

By Simon Watkins - Dec 29, 2025

• Saudi Arabia’s entry into Syria’s oil and gas sector is part of a Western-backed post-Assad strategy.
• 
  
• The agreements are operational and Gulf-led, with Saudi and UAE energy firms moving quickly into oil and gas services, field development, and seismic work.
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• The broader objective is geopolitical, not just economic.
• 
  

Saudi Arabia’s recent agreements with the Syrian Petroleum Company to help revive and develop Syria’s long-neglected oil and gas fields are not a benevolent Gulf gesture but the latest step in a carefully sequenced post-Assad strategy shaped in Washington and London. The removal of Bashar al-Assad last December -- driven as much by Syria’s pivotal geography and Mediterranean frontage as by the desire of the new U.S. administration to demonstrate its willingness to unseat entrenched autocrats -- created a vacuum that Western planners were determined not to fill with another Iraq-style occupation. Instead, they have opted for a reconstruction model fronted by powerful Arab states, with Western firms embedded behind them. The UAE’s early lead in resuscitating Syria’s gas sector was the first signal of this shift; Riyadh’s move into that sector – and its vital oil space too -- is the second, and it aligns neatly with Washington’s broader effort to re-anchor regional influence and revive the architecture of Arab?Israeli normalisation that defined Donald Trump’s first term.

The agreements between Saudi Arabia and Syria are not the usual airy-fairy declarations of intent designed to signal political goodwill with little practical follow-through. They are operational, detailed, and being driven directly by Riyadh’s Ministry of Energy, which is overseeing four of its key companies -- TAQA, ADES Holding, Arabian Drilling, and the Arabian Geophysical and Surveying Company (ARGAS) -- as they move into Syria to provide services, technical support, and field development across both oil and gas. ARGAS will deliver 2D and 3D seismic surveying and associated technical services to support exploration and drilling, while Arabian Drilling is set to supply rigs, conduct drilling and workover operations, and provide workforce training and development, according to company releases. TAQA will handle advanced, integrated solutions for the construction and maintenance of oil and gas fields and wells, and ADES Holding will initially focus on boosting output across five gas fields -- Abu Rabah, Qamqam, North Al?Faydh, Al?Tiyas, and Zumlat al?Mahar. These moves build on the UAE’s own push into Syria’s gas sector, following Dana Gas’s preliminary agreement on 12 November with Syria’s state oil company to redevelop key fields. Together, these Gulf-led initiatives will operate alongside Western efforts, after the July announcement that U.S. firms Baker Hughes, Hunt Energy, and Argent LNG are working on a broader plan to rebuild Syria’s oil, gas, and power sectors. That plan is initially centred on areas west of the Euphrates, with expansion eastward expected as soon as conditions allow.

Related: Why China Is Driving Short-Term Oil Prices But OPEC Still Holds the Lever

Despite fourteen years of civil war, the companies now moving into Syria still have substantial potential to work with. Before hostilities erupted, the country was producing around 316 billion cubic feet per day of dry natural gas and held proven reserves of 8.5 trillion cubic feet. Russia’s Stroytransgaz had begun developing the South?Central Gas Area in 2009, and by 2011, this work had lifted Syria’s natural gas output by roughly 40%. Combined oil and gas exports accounted for a quarter of government revenues at the time, making Syria the eastern Mediterranean’s leading hydrocarbon producer. After Russia’s heavy military intervention to shore up President al-Assad, Moscow and Damascus signed the 2015 Cooperation Plan, which covered the restoration of at least 40 energy facilities -- initially gas, later offshore oil -- alongside a major build-out of the power sector, analysed in full in my latest book on the new global oil market order. This included the full reconstruction of the Aleppo thermal plant, installation of the Deir Ezzor plant, and capacity expansions at the Mharda and Tishreen facilities, all aimed at reenergising the national grid and restoring central control to Damascus. In short, from the West’s perspective, much of the groundwork for Syria’s energy revival has already been laid -- and paid for -- by Russia.

A similar story applies to Syria’s oil sector. Another component of the 2015 Cooperation Plan was the repair and capacity?boosting upgrade of the Homs refinery (the other being in Banias), with Phase 1 targeting 140,000 barrels per day (bpd), Phase 2 aiming for 240,000 bpd, and Phase 3 for 360,000 bpd. Moscow’s intention was that Homs could also refine Iranian crude routed through Iraq, with onward shipments into southern Europe. Before the civil war, Syria was producing around 400,000 bpd from proven reserves of 2.5 billion barrels; earlier still -- before recovery rates declined due to the lack of enhanced oil recovery techniques -- output had approached 600,000 bpd. Europe imported more than US$3 billion of Syrian oil annually up to 2011, much of it destined for Germany, Italy, and France via the Mediterranean export terminals at Banias, Tartus, and Latakia. A wide range of international oil companies operated in Syria at the time, including the UK’s Shell, Petrofac, and Gulfsands Petroleum; France’s then?Total; China National Petroleum Corporation; India’s ONGC; Canada’s Suncor Energy; and Russia’s Tatneft and Stroytransgaz.

As the events since 2011 have repeatedly shown, Syria was never just another Middle Eastern ally; it was the linchpin of Moscow’s entire regional strategy. It offered something Russia had coveted for decades: a warm?water military presence on the Mediterranean, outside NATO’s containment arc, and within striking distance of Europe’s southern flank. The Kremlin’s naval facility at Tartus and the airbase at Hmeimim gave Moscow permanent, hard?power reach into the Levant, the eastern Mediterranean, and North Africa -- a capability it had lacked since the collapse of the Soviet Union. Syria also provided Russia with a forward operating platform for intelligence collection through its base just outside Latakia, and for arms sales, and diplomatic leverage, all underpinned by deep involvement in the country’s energy sector. More broadly, just before al?Assad’s removal by Washington and London, Russia and Iran were finalising plans for the long?anticipated ‘Land Bridge’ -- a corridor running from Tehran to Syria’s Mediterranean coastline, designed to massively expand weapons flows into southern Lebanon and the Golan Heights for use against Israel, also detailed in my latest book on the new global oil market order. Supporting infrastructure for this route was already being laid through the US$17 billion Iraq–China Strategic Development Road, intended to run from Basra to southern Turkey and plug directly into China’s Belt and Road Initiative.

For Iran, the objective was to bind the Islamic world into what it sees as an existential struggle against the broadly Judeo-Christian democratic alliance of the West, with the U.S. at its centre. This dovetailed neatly with the Chinese and Russian push for a multi-polar world in which Washington anchors only one of three dominant spheres of influence — the others led by Beijing and Moscow. The same logic has underpinned President Xi Jinping’s increasingly assertive Middle East policy, reflected in his meetings with regional leaders in December 2022 and January 2023. The agenda was clear: finalise a China–Gulf Cooperation Council Free Trade Agreement (covering Bahrain, Kuwait, Oman, Qatar, Saudi Arabia, and the UAE) and to forge a “deeper strategic cooperation in a region where U.S. dominance is showing signs of retreat”.

Neither Washington nor London could tolerate a Russia-anchored Syria – one with rebuilt energy infrastructure, restored export capacity, and permanent military bases – that would have given Moscow a durable geopolitical foothold on NATO’s southern doorstep. The removal of al-Assad and the shift to a new Western-inspired reconstruction model is therefore not simply about rebuilding Syria; it is about dismantling the most valuable Middle Eastern asset Russia had acquired in a generation. The model being used is the one initiated by Trump in his first term – a series of ‘relationship normalisation’ deals signed between major Arab countries and the West’s leading geopolitical partner in the Middle East, Israel. The UAE had been the first major signatory to such a deal, on 13 August 2020, and has long figured in Washington’s plans as a strategic partner to counter the influence of Iran, Russia, and China, a theme also explored in my latest book on the new global oil market order. U.S. officials have also regarded Saudi Arabia as a potential participant in such arrangements, encouraged by broadly positive comments from Crown Prince Mohammed bin Salman, with the likelihood of progress increasing in the event of a leadership transition in Riyadh. Against this backdrop, the new energy agreements in Syria involving the UAE and Saudi Arabia are not a loose collection of Gulf investment initiatives but a deliberate reengineering of the country’s energy and political architecture. The UAE and Saudi Arabia supply the regional legitimacy; Western firms provide the technical and operational backbone; and Washington shapes the overarching strategic design. In the process, Russia’s years of investment, military intervention, and energy?sector entrenchment have been quietly pushed aside, replaced by a reconstruction model that restores Western influence, draws key Arab states more tightly into the U.S. orbit, and reopens the pathway to broader regional normalisation.

By Simon Watkins for Oilprice.com

 

U.S. Pressures Mexico Over Fuel Supply to Crisis-Hit Cuba

By Tsvetana Paraskova - Dec 29, 2025

• U.S. lawmakers are pressuring the U.S. Administration to demand Mexico end its subsidized oil shipments to Cuba by leveraging the 2026 renegotiation of the USMCA trade agreement.
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• Mexico, through a subsidiary of its state oil company Pemex, has defended its shipments of fuel to Cuba as humanitarian aid intended to prevent widespread blackouts on the island.
• 
  
• An investigation found that Mexico shipped over $3 billion worth of subsidized fuel to Cuba in just four months of 2025, a figure three times higher than the shipments during the final two years of the previous administration.

The U.S. blockade of Venezuela to prevent sanctioned tankers from shipping oil to and from the South American country is not the only geopolitical game involving the United States in its backyard in the Western Hemisphere. 

U.S. lawmakers are not happy with Mexico sending fuel shipments to Cuba. Power outages and massive blackouts have become more frequent on the Communist-run island since shipments from sanctioned Venezuela dwindled and left Cuba’s petroleum-dependent power system at the mercy of alternative supplies.  

Some of this supply has come over the years from Mexico, which continues to insist that the shipments are of a humanitarian nature and aim to “avoid a crisis of blackouts”.  

U.S. lawmakers representing Miami and Florida have urged the Trump Administration to pressure Mexico with the Cuba card when 

The United States-Mexico-Canada Agreement (USMCA) comes up for review in 2026. They insist the U.S. Administration should require Mexico to end shipments of oil to Cuba, along with stepping up efforts to combat narco cartels. 

In just four months of 2025, between May and August, Mexico shipped more than $3 billion worth of subsidized fuel to Cuba through Gasolinas Bienestar, a subsidiary of state oil company Pemex, according to an investigation by Mexicanos Contra la Corrupción y la Impunidad (MCCI). The figure is three times higher than the total shipments during the final two years of the previous administration. 

MCCI found that at least 58 fuel shipments — including gasoline, diesel, and crude — departed from Mexican ports over just four months. The cargoes were tracked through maritime monitoring platforms, showing consistent routes between Mexico and Cuba. 

Mexico’s President Claudia Sheinbaum this week defended the country’s supply of fuel to Cuba, the most recent of which was an 80,000-barrel shipment from Pemex. 

Cuba is in desperate need of oil and fuel to keep the lights on, especially in light of the U.S. blockade offshore Venezuela, which further restricts vital supplies that previously flowed from Venezuela to the island nation. 

Even before the blockade, for the fifth time this year, Cuba suffered a massive power outage after a partial collapse of the electrical grid. 

Cuba’s power system has deteriorated in recent years as the fuel and oil supply crisis has hit the old oil-fueled power plants heavily.  

Cuba’s power generation is heavily dependent on oil products. According to the International Energy Agency (IEA), Cuba’s energy supply is mainly oil-based, with oil products accounting for more than 80% of power generation.

Oil also represents 84% of Cuba’s total energy supply. 

However, Cuba’s imports of oil and fuel, mostly from Venezuela, Russia, and Mexico, have slumped as production at these countries has been constrained by a lack of investment in Mexico’s case, and U.S. sanctions in Venezuela and Russia’s case.  

Cuba’s outdated power plants and weak grid now supply just 50–70% of electricity demand in the country, causing almost daily blackouts and repeated nationwide outages.

Reliance on poor-quality heavy crude and unstable oil imports from Venezuela has forced Cuba to turn to Mexico and China for emergency fuel shipments. Cuba is also considering investment in solar power generation to try to replace some of its dependence on oil for its electricity supply.   

Mexico’s Sheinbaum said this week, “Later, we will make public what the price is as well as the cost to transport and unload the oil.”

“The motives are humanitarian for the people of Cuba,” the Mexican president added, as carried by the Latin Times.  

But Miami Republican U.S. Rep. Carlos Giménez, who chairs the House Homeland Security Subcommittee on Transportation and Maritime Security, last month called on U.S. Secretary of State Marco Rubio and Treasury Secretary Scott Bessent to ensure “Mexico ends its disturbing relationship with the murderous regime in Havana.” 

In a letter obtained by the Miami Herald, Giménez asked Rubio and Bessent to demand in the 2026 renegotiation of the USMCA that Mexico “step up efforts in combating and eliminating narco-terrorist organizations… halt trafficking of medical professionals from Cuba, victims of modern-day slavery” and “demand Mexico end its oil shipments to the regime in Havana.”  

By Tsvetana Paraskova for Oilprice.com 

The Permian Is Drowning in Its Own Wastewater

By Irina Slav - Dec 29, 2025

• The Permian basin's massive oil production from hydraulic fracturing generates huge amounts of wastewater, and the industry is running out of safe places to dispose of it.
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• The Texas Railroad Commission has restricted new disposal wells due to widespread increases in reservoir pressure, leading to drilling hazards, ground deformation, and seismic activity.
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• Potential solutions, such as treating the water for release into rivers, face regulatory hurdles and would add significant, unwelcome costs to producers operating below $60 per barrel West Texas Intermediate.

The Permian Basin is the largest contributor to U.S. oil production, accounting for nearly half of total production in both 2024 and 2025. But success comes at a price, and in the Permian’s case, the price is huge amounts of wastewater—and the industry is running out of places to store it.

Hydraulic fracturing, which is the dominant way of extracting oil in the Permian, is a water-intensive process. Fracking involves injecting chemicals and sand into the horizontal well to open up the oil-bearing rock and keep it open. The longer the laterals got, the more water needed to be injected. This water, which is mixed with chemicals, then gets disposed of in special wells. But there are too many of those, and they are overflowing, according to reports.

The first signs of serious trouble emerged earlier this year, when the Texas Railroad Commission sent out notices to companies applying for licenses for wastewater disposal wells in the basin, stating that there were ground pressure issues caused by wastewater disposal. The number of new ones was to be restricted.

Wastewater disposal, the Railroad Commission wrote in the letters sent out in May, “has resulted in widespread increases in reservoir pressure that may not be in the public interest and may harm mineral and freshwater resources in Texas.” The RRC added that “Drilling hazards, hydrocarbon production losses, uncontrolled flows, ground surface deformation, and seismic activity have been observed.”

It is difficult to find a solution to this problem without compromising oil production, and while local communities may not have a big problem with that, the industry will. So decision-makers in relevant positions are considering options. One of these, per a recent Bloomberg report, is releasing the water—after treating it—into local rivers. 

The report cited regulatory filings concerning the issue of permits to energy companies to treat their wastewater and then release it into the Pecos River near New Mexico. Texas Pacific Land Corp. and NGL Energy Partners were two of the companies named as potential receivers of such a permit. At least one of these could be awarded by the end of March 2026, the Bloomberg report also said, citing Texas Pacific Land Corp.

If the wastewater problem is to be solved, however, more such permits would be needed—unless opposition to them emerges and spreads. There is also the issue of additional costs, Bloomberg noted. Treating the water to make it of suitable quality to be poured into a river would add to oil producers’ costs, and this is not the time to have more costs pile up for most producers, with West Texas Intermediate firmly below $60 per barrel. What’s more, Bloomberg reports that the safety of the whole procedure of releasing treated water into rivers has not yet been confirmed.

The Texas Commission on Environmental Quality has already signaled it will not be handing out wastewater-to-river permits like candy. The watchdog told Bloomberg it was monitoring the water quality at four locations along the Pecos River and two locations in its Red Bluff Reservoir—while considering the first of those permits.

The Wall Street Journal, meanwhile, reported that while regulators are looking for solutions to the wastewater problem, pressure is building in the rock, suggesting it may come to affect production. There is so much wastewater across the Permian that it is moving into old wellbores, causing geysers that cost a lot to clean up, the publication said, adding that pressure in injection reservoirs in some parts of the Permian has reached 0.7 pounds per square inch per foot. This is 0.2 pounds higher than the threshold over which liquid can flow up to the surface and potentially affect drinking water.

The Wall Street Journal noted that drillers in the Delaware Basin are pumping between 5 and 6 barrels of fluid for every barrel of oil they recover. That, it appears, is a lot, and the practice, as suggested by these reports, is unsustainable. The current solutions also appear to be falling short, mostly consisting of switching from deep disposal wells to shallower ones to avoid changes in seismic activity, as reported by the U.S. Geological Survey.

The shallow disposal wells have fixed the seismic problem and are currently receiving three-quarters of all wastewater produced in the Permian, the WSJ reported, noting, like Bloomberg, the unwanted water geysers that the migrating water is causing. One of these costs $2.5 million to plug, with the Texas Railroad Commission also shutting the injection wells that it suspected were leading to leaks, the Wall Street Journal wrote.

Meanwhile, the industry is trying to fortify its wells against wastewater seeping from injection wells, which also leads to additional costs. “Bit by bit, it adds cost, it adds complexity, it adds mechanical challenges,” one Chevron executive told the WSJ. On top of this, the wastewater is seeping into the oil and gas reservoirs, and there seems little that anyone can do about it except spend more to remove it. The issue with excess wastewater in Texas remains a challenge to an industry that is pumping almost half of the nation’s oil.

By Irina Slav for Oilprice.com 

Duke Energy Takes Early Step Toward New Nuclear Build in North Carolina

By Charles Kennedy - Dec 30, 2025

Duke Energy has formally entered the early stages of nuclear development planning in North Carolina, submitting an early site permit (ESP) application to the U.S. Nuclear Regulatory Commission for land near its Belews Creek Steam Station in Stokes County.

The filing, announced on December 30, marks the first time Duke has pursued an ESP and reflects a broader effort by U.S. utilities to keep nuclear power on the table as electricity demand rises and decarbonization pressures intensify. While the move does not commit the company to construction, it significantly advances licensing groundwork and reduces long-term regulatory and financial risk should Duke later decide to build.

An ESP is an optional NRC process that evaluates environmental and site safety issues independently of a specific reactor design. By resolving these issues upfront, utilities can shorten timelines and lower uncertainty if projects proceed. Duke says the strategy is aimed at protecting both customers and investors as it evaluates next-generation nuclear options.

The application is technology-neutral and includes six potential reactor designs—four small modular reactors (SMRs) and two non-light-water reactors. Notably, Duke excluded large traditional light-water reactors, even though it already operates 11 such units across the Carolinas. The emphasis on SMRs underscores growing industry interest in smaller, factory-built reactors that promise lower upfront capital costs and more flexible deployment, though none have yet been built at commercial scale in the United States.

Company executives framed the submission as a measured step rather than a firm commitment. Duke Energy has not made a final investment decision, but if further evaluation supports the economics and performance of SMRs at the site, the utility plans to add up to 600 megawatts of advanced nuclear capacity by 2037. The first unit could enter service as early as 2036.

Nuclear power remains a central pillar of Duke’s long-term resource planning, particularly in the Carolinas, where coal retirements and load growth from data centers, manufacturing, and electrification are straining existing capacity. Unlike intermittent renewables, nuclear plants provide continuous baseload generation, a feature utilities increasingly value as grids become more complex.

The Belews Creek location already hosts a coal-fired plant, which could ease infrastructure and transmission challenges if a nuclear facility were eventually developed. Similar brownfield or adjacent-site strategies are being explored by other U.S. utilities seeking to replace retiring fossil assets without overhauling local grid connections.

Duke’s move comes amid renewed federal support for nuclear energy, including tax credits for existing plants and incentives for advanced reactors under recent U.S. energy and climate legislation. Still, the sector faces persistent hurdles, including cost overruns, long development timelines, and public skepticism - factors that make early-stage risk reduction especially attractive.

By pursuing an ESP now, Duke is effectively buying time and flexibility. Whether SMRs ultimately deliver on their promise remains uncertain, but utilities like Duke are signaling that nuclear power, in some form, is likely to remain part of the U.S. energy mix well into the next decade.

By Charles Kennedy for Oilprice.com

Argentina’s Shale Boom Propels It Past Colombia in Oil Output

By Matthew Smith - Dec 30, 2025

• Rapid growth in Vaca Muerta shale oil has pushed Argentina’s crude output to near-record levels, making it the region’s fourth-largest producer.
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• While oil production continues to surge, natural gas output has declined due to infrastructure constraints, maintenance, and weaker prices.
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• YPF’s low-cost shale operations and aggressive investment plans position it as the primary driver of Argentina’s long-term hydrocarbon expansion.
• 
  

Argentina, in a surprise development, overtook Colombia to become South America’s fourth-largest oil producer. The country is undergoing a once-in-a-generation unconventional hydrocarbon boom, which began with Buenos Aires nationalizing integrated energy major YPF in 2012. Since then, Argentina’s oil and natural gas output has kept soaring higher, regularly hitting new monthly highs as volumes of shale oil and gas production grow. It is Argentina’s national oil company, YPF, which is at the forefront of the boom with it responsible for this strong production growth.

For November 2025, Argentina’s crude oil production, despite falling from the October 2025 record of 849,646 barrels per day to 844,386 barrels per day, was still an impressive 12.5% higher than a year earlier. This was the first month out of the last six where output did not rise to a new record high. Rapidly growing shale oil production in the Vaca Muerta shale, Spanish for Dead Cow, is driving Argentina’s stunning production growth. For November 2025, shale oil output hit a new monthly record of 578,461 barrels per day, a 30.68% year over year increase, which saw it responsible for 68.51% Argentina’s total production. 

Natural gas production, however, continues to decline. Output dropped 7% year over year to 4.2 billion cubic feet per day, the lowest level since December 2023. This represents a sharp drop from the record 5.7 billion cubic feet per day pumped for July 2025. It is rising shale gas output from the Vaca Muerta which is responsible for the solid growth of Argentina’s natural gas production over the last five years. For November 2025, shale gas production fell 1% year over year to 2.7 billion cubic feet daily, which despite being significantly less than the record 3.8 billion cubic feet per day reported for July 2025, still comprised 65% of Argentina’s total gas production.

Since July 2025, a combination of well maintenance, reduced drilling activity due to weaker spot prices, and a lack of infrastructure, notably storage and pipeline facilities, which is impacting takeaway capacity, are weighing on output. Indeed, the lack of pipeline and other transportation infrastructure has long been viewed as a key constraint with the potential to impact production in the Vaca Muerta. Although the increasingly prolific shale formation and Argentina’s national oil company YPF will be responsible for further production growth.

The 8.6-million-acre Vaca Muerta is a massive shale formation, roughly the size of Switzerland, located in the Neuquén Basin in northern Patagonia. It is among the world’s largest unconventional hydrocarbon resources and is frequently compared to the prolific Eagle Ford and Permian shales. The Vaca Muerta is estimated to contain 16 billion barrels of light tight oil and 308 trillion cubic feet of tight gas, making it the world’s fourth-largest unconventional oil and second-largest unconventional gas reserve. According to analysts, characteristics such as superior shale thickness, greater quantities of biological material, higher reservoir pressures, and increased well productivity make the Vaca Muerta superior to major U.S. shale plays.

After a decade of development, the Vaca Muerta is responsible for 69% of Argentina’s oil production and 65% of the country's natural gas output. With less than a tenth of the formation under development, there is tremendous production growth ahead. By the end of the decade, Argentina’s crude oil output is expected to hit at least 1 million barrels per day, with some analysts forecasting 1.5 million barrels per day by 2030. This is a massive increase over the 787,395 barrels per day lifted for the first 11 months of 2025. Natural gas output is expected to surpass 6 billion cubic feet per day by 2030, driven by the Vaca Muerta’s rising shale gas production.

It is national oil company YPF and its unconventional hydrocarbon acreage in the Vaca Muerta that will be responsible for most of the expansion of Argentina’s hydrocarbon output. The integrated energy major, which was nationalized by President Cristina Fernández de Kirchner in April 2012, holds the most acreage in the Vaca Muerta, controlling 2.9 million gross acres. YPF, after being the first energy company to start developing conventional energy assets in the Vaca Muerta, is the largest shale oil and gas producer in the formation. This first-mover status is delivering a tremendous windfall for the energy company.

During November 2025, YPF lifted 397,420 barrels of crude oil and 936 million cubic feet of natural gas per day. This amounts to 47% and 22% respectively of Argentina’s total oil and gas production respectively, making the national oil company the country’s largest hydrocarbon producer. For the same period, YPF lifted 315,937 barrels of shale oil and 725,716 million cubic feet of natural gas per day. This represents 79.5% and 77.5%, respectively, of the energy company’s oil and natural gas production for November 2025.

YPF is focused on developing the Vaca Muerta with plans to become a pure shale oil and gas producer. The company plans to achieve this by divesting higher-cost mature conventional oilfields while investing tremendous sums of capital to develop its Vaca Muerta acreage. Between 2025 and 2030, YPF plans to invest $36 billion with annual capital expenditure peaking at $6.8 billion during 2029. This will give YPF’s reserves and production a solid lift. By the end of 2024, the energy company held just over 1 billion barrels of proven reserves, of which 78% or 854 million barrels are unconventional oil located in the Vaca Muerta. 

YPF’s shale acreage is proving to be particularly profitable. For the third quarter of 2025, Argentina’s national oil company reported low lifting costs averaging $8.80 per barrel, with the company only spending $4.60 per barrel to lift oil from its Vaca Muerta acreage. Those numbers underscore just how profitable YPF’s upstream shale oil operations are, even in the current difficult operating environment impacted by weaker oil prices. CEO Horacio Marín believes YPF can sustain profitable operations even if prices drop to $40 or $45 per barrel. In an interview with Infobae, he stated: “We made ourselves resilient at less than $40 a barrel, and at $45 we can develop all of Vaca Muerta.”

It will be YPF which will be responsible for Argentina’s unconventional oil and gas production soaring higher. Forecasts vary, but analysts believe the country will be lifting 1 million to 1.5 million barrels per day by 2030, while natural gas output is expected to exceed 6 billion cubic feet per day. This will deliver a generous economic windfall for Argentina with the country emerging as a net energy exporter during 2024, a year when the economically crisis-riven country reported its largest energy surplus in nearly two decades.

By Matthew Smith for Oilprice.com