The renewed Russian oil waiver forms part of a broader strategy aimed at stabilizing global energy markets, which have experienced sharp volatility during the U.S.-Israeli war with Iran. Countries across Asia, grappling with the effects of a global energy shock, had urged Washington to facilitate alternative supply flows. Notably, just two days before the announcement, Treasury Secretary Scott Bessent had indicated that the U.S. would not extend the waiver for Russian oil or a similar provision for Iranian oil due to lapse on Sunday. Meanwhile, global oil prices dropped by 9% to about $90 per barrel following Iran’s temporary reopening of the Strait of Hormuz, a critical transit route. However, the International Energy Agency has warned that the conflict has already triggered the most severe disruption to global energy supplies on record.

The ongoing war, entering its eighth week on Saturday, has inflicted damage on more than 80 oil and gas facilities across the Middle East. Tehran has cautioned that it could again shut the Strait of Hormuz if the recent U.S. Navy blockade of Iranian ports continues. Elevated oil prices have emerged as a political concern for Republicans ahead of the November midterm elections. According to a U.S. source, partner countries engaged in meetings linked to the Group of 20, World Bank, and International Monetary Fund in Washington this week pressed for an extension of the Russian oil waiver. The issue was also raised during a call between Trump and Prime Minister Narendra Modi, given India’s position as a major buyer of Russian crude.

Separately, the waiver covering Iranian oil, issued on 20th March 2026, enabled approximately 140 million barrels to enter global markets, easing supply pressures, Bessent noted last month. Nevertheless, lawmakers from both parties have criticized such waivers, arguing they risk supporting the economies of Iran and Russia during active conflicts. Concerns have also been raised that these measures could weaken Western efforts to curb Russia’s war financing and create friction with allies. Ursula von der Leyen has stated that now is not the time to ease sanctions. Adding to the debate, Kirill Dmitriev said the extension could impact another 100 million barrels of Russian oil, bringing the combined total under both waivers to 200 million barrels.

A major driver behind this natural gas production growth is the expansion of U.S. liquefied natural gas (LNG) exports, which are expected to absorb a large share of incremental supply. Export volumes are projected to climb from 15 billion cubic feet per day (Bcf/d) in 2025 to over 30 Bcf/d by 2050 in most scenarios. These projections are largely centered around the Counterfactual Baseline case, while the Combination case records the highest export levels due to the absence of certain transportation and electricity market policies. Without these policies, liquids consumption increases, leading to higher Brent crude oil prices. Because LNG pricing is often indexed to crude oil, U.S. LNG becomes more competitive in international markets. At the same time, lower electricity demand from electric vehicles (EVs) reduces domestic gas consumption for power generation, freeing up additional volumes for export and reinforcing natural gas production growth.

Domestic consumption patterns also contribute to the overall expansion. In most scenarios, U.S. natural gas demand rises steadily, particularly within the electric power sector. Consumption for power generation is projected to grow  by between 2.9 Bcf/d and 15.2 Bcf/d in 2050, from 35.2 Bcf/d in 2025 marking the largest increase among end-use sectors. This trend is supported by higher electricity generation needs and policy conditions that limit renewable deployment. In the Counterfactual Baseline case, total domestic consumption increases from 90.8 Bcf/d in 2025 to 108 Bcf/d in 2050. However, in the Combination case, consumption is lower at approximately 98 Bcf/d, largely due to reduced demand from EV-related power usage. Of this difference, around 7 Bcf/d is redirected to LNG exports, while the remaining 3 Bcf/d is not absorbed, slightly moderating output levels. Even so, the broader outlook continues to emphasize consistent natural gas production growth across most scenarios.

Russian media reported that the tanker Anatoly Kolodkin is carrying what was described as a humanitarian shipment of 100,000 tonnes of crude oil. The arrival of this Russian oil cargo follows warnings from the World Health Organization (WHO), which last week highlighted the strain on Cuba’s healthcare system due to limited fuel supplies, with hospitals struggling to sustain emergency and intensive care services. The situation worsened significantly after 3rd January 2026, when U.S. forces seized Venezuelan leader Nicolás Maduro, cutting off a key source of subsidised oil to the island and deepening the ongoing energy crisis.

Just over a week ago, the U.S. Treasury Department added Cuba to a list of countries prohibited from receiving oil shipments from Russia. However, Trump appeared to soften that stance, telling journalists aboard Air Force One that he had no problem with Russia delivering oil to Cuba. The tanker containing  Russian oil cargo will potentially offer temporary relief to the country’s strained energy system.

Kremlin spokesman Dmitri Peskov said Russia viewed the delivery as its duty to step up and provide necessary assistance to our Cuban friends. Cuban authorities have framed the tanker’s arrival as effectively breaking the U.S.-imposed oil blockade. While the shipment may provide a short-term lifeline, broader negotiations between Cuba’s Communist government, led by President Miguel Díaz-Canel, and the Trump administration remain complex, with both sides maintaining firm political and economic positions. Cuba’s economic challenges, already severe since the end of the Cold War, have been exacerbated by declining tourism after the coronavirus pandemic, internal economic mismanagement, and the tightening fuel restrictions.

Once operational, the Raia gas project is expected to deliver up to 16 million cubic metres of natural gas per day. This output could account for around 15% of Brazil’s natural gas demand, strengthening national energy security while also contributing to Equinor’s international equity production and long-term cashflow. The project is operated by Equinor (35%) in partnership with Repsol Sinopec Brasil (35%) and Petrobras (30%). The drilling work builds on the partners’ extensive deepwater expertise, including prior collaboration on the Bacalhau field, where the same drillship previously participated.

Alongside drilling, work continues on integrating and preparing the floating production, storage and offloading unit (FPSO), a central component of the Raia gas project’s development concept. The FPSO will process oil/condensate and gas produced from subsea wells.

Natural gas from the Raia gas project will be transported via a 200-kilometre pipeline linking the FPSO to Cabiúnas in Macaé, Rio de Janeiro state. With a total investment of around USD 9 billion, the development represents Equinor’s largest international commitment to date. The FPSO is projected to rank among the most carbon-efficient globally, with average CO₂ emissions intensity of approximately 6 kg per barrel of oil equivalent.

“Raia is Equinor’s largest project under execution and marks the deepest water depth operation in our portfolio. Together with our partners and suppliers, we are applying world-class technology and decades of offshore expertise. While drilling takes place, integration and commissioning activities on the FPSO are progressing well putting us on track towards a safe start of operations in 2028”, Says Geir Tungesvik, executive vice president, Projects, Drilling and Procurement.

Since the U.S. intervention, the outlook has improved, with international oil companies beginning to re-engage with the country. This renewed interest is partly driven by a legislative overhaul designed to provide greater operational clarity and stability. The newly enacted law caps royalty rates at 30% while allowing flexibility for project-specific adjustments depending on investment requirements and competitiveness. Following its approval earlier this year, Venezuela’s interim president Delcy Rodriguez said she anticipated fresh oil investments reaching as much as $1.4 billion this year. The policy shift underpins expectations that production levels such as 1.1 million bpd could be sustained or gradually expanded.

The legislation also outlines a revised operational framework for private sector participation. Under the new rules, companies “will assume full management of the activities at its own expense, account, and risk, after demonstrating its financial and technical capacity through a business plan” subject to approval by the Venezuelan oil ministry. While operational control is extended to private firms, ownership of the underlying resources will remain with the Venezuelan state. This structure is intended to balance foreign investment incentives with state control of reserves.

In response, major energy companies are exploring expanded involvement. Chevron is reportedly in discussions to broaden its Petropiar joint venture with PDVSA, while Shell is evaluating opportunities in eastern Venezuela, particularly in the Monagas North area, which contains some of the country’s limited light and medium crude reserves. Shell is also considering natural gas developments both offshore and onshore. These developments highlight a cautious but notable return of international players as Venezuela seeks to rebuild output levels around 1.1 million bpd.

The Copoazu-1 well is situated around 36 kilometers from the coastline, at a water depth of 964 meters, and approximately 8 kilometers from the Sirius-1 discovery and Sirius-2 appraisal wells. Petrobras noted that this proximity enhances the relevance of the Colombia offshore gas discovery within the broader exploration framework of Block GUA-OFF-O. Drilling operations began on 11th November 2025, and have progressed under conditions that prioritize safety and environmental responsibility. Gas-bearing intervals were identified through electric logs and fluid sampling, confirming hydrocarbons in an additional target beyond the primary objective, thereby increasing the overall significance of the find.

The company indicated that further laboratory analysis will be carried out to better characterize the gas-bearing zones. Petrobras highlighted that its activities in Block GUA-OFF-O align with its long-term strategy of replenishing oil and gas reserves through frontier exploration and partnerships. This approach is intended to sustain global energy supply amid the ongoing energy transition. Through its subsidiary, Petrobras International Braspetro B.V – Colombia Branch (PIB-COL), Petrobras operates the consortium  alongside Ecopetrol.

The discovery also reflects ongoing offshore drilling investments, including the deployment of the Noble Discoverer semi-submersible rig, which was contracted in December 2023 to support operations in Colombia. Petrobras later extended the rig’s assignment by 390 days in April 2025. The DSS-21 column-stabilized, dynamically positioned, sixth-generation unit is capable of operating in water depths of up to 10,000 feet (3.05 kilometers) and can drill to a maximum depth of 40,000 feet (12.19 kilometers). Petrobras emphasized that the latest Colombia offshore gas discovery underscores the company’s continued focus on expanding its exploration portfolio while advancing offshore development in the region.

The policy changes underscore mounting pressure tied to Venezuela oil sanctions as Washington responds to surging fuel costs. Oil markets have been rattled since Iran halted traffic through the Strait of Hormuz, a critical chokepoint for global supply. In the U.S., gasoline prices have climbed significantly, with the national average for regular fuel reaching $3.84 per gallon on 18th March 2026, compared to $2.98 before the war began on 28th February 2026. Following the January 2026 ouster and arrest of Nicolás Maduro during a U.S. military operation, Trump stated that the U.S. would effectively “run” Venezuela and manage its oil exports. The newly issued license provides limited relief, permitting companies that existed before 29th January 2025 to engage in transactions otherwise restricted under sanctions.

Officials say the measures tied to Venezuela oil sanctions are designed to stabilize markets in the short term. White House press secretary Karoline Leavitt said the Jones Act waiver would help “mitigate the short-term disruptions to the oil market” during the Iran war and would “allow vital resources like oil, natural gas, fertilizer and coal to flow freely to U.S. ports.” The administration has also tapped the strategic petroleum reserve and temporarily eased sanctions on certain Russian oil shipments for 30 days. Meanwhile, Vice President Vance and other officials are expected to meet with the American Petroleum Institute to discuss production and market conditions.

Despite the easing of Venezuela oil sanctions, strict controls remain in place. Payments for Venezuelan oil cannot go directly to PDVSA but must be routed through a U.S.-controlled account, ensuring oversight of financial flows. Transactions involving Russia, Iran, North Korea, Cuba and some Chinese entities are prohibited, as are dealings in Venezuelan debt or bonds. The license also bans payments in gold or cryptocurrency, including the petro.

While Venezuela holds the world’s largest oil reserves, years of corruption, mismanagement and prior sanctions reduced output from 3.5 million barrels per day in 1999 to under 400,000 barrels per day in 2020, highlighting the long-term impact of restrictions now partially eased.

Commenting on the milestone, Venture Global CEO Mike Sabel praised the company’s progress and highlighted the pace of its development strategy. He said, “The tireless dedication of our team has enabled us to reach five final investment decisions in less than seven years, positioning us to become the largest U.S. exporter of LNG once CP2 is fully online.”

The CP2 LNG Phase 2 project is part of a broader expansion plan that will give the CP2 facility a peak production capacity of 29 Million Tonnes Per Annum (MTPA) once completed. Nearly all of that nameplate capacity has already been committed under long-term sales agreements, with customers primarily located in Europe and Asia. As a result, the development is viewed as strategically important for global energy supply and security. Across its three Louisiana projects, Venture Global now holds a total contracted capacity of more than 49 MTPA, covering nearly all of its planned production capacity.

Financing for CP2 LNG Phase 2 has been supported by a large consortium of international banks, reflecting strong global demand for investment in U.S. LNG infrastructure. The lender group includes well known banks and organizations from all across North America, Europe, and Asia, underscoring the international interest surrounding the project. Bank of America, Bank of China, Barclays, Canadian Imperial Bank of Commerce, Deutsche Bank, Goldman Sachs, J.P. Morgan Chase, and Wells Fargo are among many others who have participated in the project.

Two major financial institutions served as Lead Arrangers for the project’s Construction Term Loan and Working Capital Facility. Banco Bilbao Vizcaya Argentaria (BBVA) and MUFG Bank, Ltd. (MUFG) coordinated the financing structure. Legal counsel for the transaction was provided by Latham & Watkins LLP, representing Venture Global, while Skadden, Arps, Slate, Meagher & Flom LLP advised the lenders involved in the financing arrangements. Together, these steps mark a significant stage in the advancement of CP2 LNG Phase 2 as Venture Global continues building its LNG export capacity in Louisiana and beyond it.

The Appalachia region in the Northeast remained the country’s largest producing area in 2025, accounting for 31%, or 36.6 Bcf/d, of total marketed output. However, expansion in the region has slowed in recent years due to limited pipeline takeaway capacity needed to move gas to demand centres. A key development occurred in June 2024, when the Federal Energy Regulatory Commission authorized the Mountain Valley Pipeline to begin operations. The added infrastructure capacity, combined with stronger Henry Hub prices in 2025, helped increase production in the region by 1.1 Bcf/d compared with a much smaller rise of 46 million cubic feet per day Bcf/d in 2024. Despite infrastructure challenges, Appalachia remains central to sustaining record natural gas production levels nationwide.

Strong output growth was also recorded in the Permian region of Texas and New Mexico, which represented 23% of U.S. marketed natural gas production in 2025 and delivered roughly half of the country’s annual increase. Production in the basin rose 11%, or 2.7 Bcf/d, to average 27.7 Bcf/d. Much of the increase stems from associated gas generated during oil extraction. While West Texas Intermediate (WTI) crude oil prices declined from $77/barrel (b) in 2024 to $65/b in 2025, the price level continued to support oil-focused drilling activity in the region. According to the Dallas Fed Energy survey, industry executives reported breakeven prices of $61/b (Midland Basin) and $62/b (Delaware Basin) in 2025, while a steadily rising gas-to-oil ratio further contributed to expanding supply and reinforcing record natural gas production.

In the Haynesville region spanning Louisiana and Texas, output averaged 14.9 Bcf/d in 2025, representing a 4% increase compared with the 2024 annual average. The rise in Henry Hub prices between 2024 and 2025 enabled drilling to remain economically viable despite deeper and more expensive well development. Wells in the Haynesville formation typically reach depths of 10,500 feet to 13,500 feet, significantly deeper than the 4,000 feet to 8,500 feet common in the Appalachia region. Even with those higher costs, the formation’s proximity to liquefied natural gas export terminals and major industrial consumers along the U.S. Gulf Coast continues to attract operators.

The P-78 is deployed in the Búzios field in the Santos Basin, located approximately 180 to 230 km off the coast of Rio de Janeiro, Brazil. Permanently moored at a water depth of around 2,100 meters using a spread-mooring system, the vessel ranks among the largest FPSOs ever delivered to Brazil. The facility is designed to produce up to 180,000 barrels of oil per day and 7.2 million cubic metres of gas per day, with a minimum storage capacity of 2 million barrels of crude oil. Through the six P-Series FPSO projects Seatrium is building – P-78, P-80, P-82, P-83, P-84 and P85. Brazil is expected to gain an additional 1.305 million barrels of oil per day of production capacity.

The achievement was supported by extensive collaboration with Petrobras and Seatrium’s international vendor network. Together, they worked to ensure that critical systems were fully prepared for operation, including the main process compressors, export compressors, and gas injection compressors. These systems are essential to enabling the safe and efficient introduction of gas injection into the production process. Throughout the development and commissioning phases, Seatrium maintained strict safety, quality, and operational standards across all participating facilities. Delivering the first gas injection according to schedule reflects the company’s strong Health, Safety and Environment performance, as well as its consistent track record of completing complex offshore energy projects on time.

Following the successful milestone, Seatrium is moving forward toward the next key phase of the project, which includes completion of the delivery stage and the Final Acceptance of the vessel by Petrobras. The company is focused on ensuring a seamless transition to full operations and supporting the long-term performance of the FPSO.