Market Valuation and Long-Term Forecast

In terms of overall market valuation, the industry is poised for steady, reliable expansion over the coming decade. As of 2024, the market size was firmly established at an estimated USD 230.38 Billion. Stepping into the core forecast period, the market is projected to reach a valuation of USD 238.77 Billion in 2025 and is expected to continuously expand to a robust USD 341.39 Billion by the year 2035. This consistent upward trajectory represents a compound annual growth rate (CAGR) of 3.64% spanning the 2025 to 2035 timeframe. This growth curve underscores the persistent global reliance on traditional energy resources, even as the broader transition to alternative energy begins to take hold and reshape long-term strategic planning for infrastructure developers globally.

Primary Market Drivers: Energy Demand and Geopolitical Security

The continuous expansion of this market is heavily stimulated by multiple intertwined drivers, primarily the unyielding escalation in global energy demand. Driven by rapid population growth and widespread industrialization, particularly in developing economies, the fundamental need for reliable, accessible energy sources is intensifying at a rapid pace. Current macroeconomic projections suggest that total global energy consumption could rise by approximately 30% by the year 2040. To satisfy this immense appetite, drastically enhanced storage solutions are an absolute necessity. Furthermore, the inherent volatility of energy prices compels nations and facility operators to prioritize strategic storage to manage complex supply and demand imbalances effectively.

Alongside raw consumption demand, strategic geopolitical factors heavily influence future market dynamics. Tensions and instability in primary oil-producing regions consistently threaten to disrupt global supply chains, prompting nations to aggressively bolster their strategic reserves. A highly proactive approach to energy security has emerged across the globe; recent data indicates that various nations are actively enhancing their strategic petroleum reserves, with ambitious targets aiming to hold up to 90 days of net imports. This geopolitical imperative ensures a continuous flow of capital into the expansion and modernization of storage infrastructure to safeguard national economies against potential supply shocks.

Transformative Market Shifts, Trends, and Technological Integration

A major shift defining the future of the oil and gas storage market is the deep integration of technological innovation and facility digitalization. The industry is moving rapidly away from purely mechanical operations toward highly automated, intelligent frameworks. Technological advancements such as real-time monitoring, predictive analytics, and automated smart sensors are becoming standard operational requirements. These technologies allow for the exact, continuous monitoring of storage conditions, significantly reducing the environmental risks and operational costs associated with dangerous leaks and spills. Furthermore, there is a pronounced shift toward modular storage solutions, which afford operators critical flexibility and the ability to rapidly scale or deploy infrastructure as market demands fluctuate.

Simultaneously, the industry is navigating a monumental shift toward operational sustainability. Stringent regulatory frameworks and updated environmental standards are forcing a rigorous reevaluation of traditional storage methods. Governments globally are demanding minimized environmental impacts, often requiring costly structural upgrades like secondary containment systems. In response to the broader carbon-reduction movement, operators are integrating renewable energy sources directly into their storage strategies, paving the way for advanced hybrid storage models. The accelerated rise of alternative energy carriers, notably biofuels and hydrogen, requires highly innovative storage systems capable of safely handling diverse and complex fuel types, presenting both distinct engineering challenges and substantial growth opportunities over the forecast period.

Comprehensive Segmentation Analysis by Storage Type

Analyzing the market through the lens of storage methodologies reveals distinct preferences and emerging engineering tactics. Above Ground Tanks remain the dominant and largest segment in the market. Highly favored for their overall practicality, visual accessibility, ease of maintenance, and significantly faster installation times, these tanks cater effectively to diverse environmental conditions. This segment is expected to maintain the highest total valuation in the market. Below Ground Tanks represent another substantial, steady portion of the market. Floating Storage Units, which provide vital offshore flexibility for maritime transport, are expected to have some growth too.

However, the most strategically significant shift in storage methodology is the rapid emergence of Underground Caverns, which currently stand as the fastest-growing segment in the industry. As environmental regulations tighten globally and the sheer volume of required strategic storage increases, underground caverns provide unparalleled volumetric efficiency, space-saving benefits, and highly enhanced security with minimal surface-level environmental footprints.

Evolution of Material Types in Storage Construction

The choice of construction material is rapidly evolving as the industry attempts to balance traditional durability with modern efficiency and ecological needs. Steel remains the undisputed dominant material in the market, commanding the largest overall share due to its proven, multi-decade strength, longevity, and exceptional resistance to harsh environmental elements. The steel segment is fully projected to maintain its global leadership.

Conversely, Fiber Reinforced Plastic (FRP) is swiftly gaining massive traction as the fastest-growing material segment. As the market increasingly prioritizes logistical sustainability and operational efficiency, FRP offers highly appealing physical characteristics, primarily its significant weight reduction, superior resistance to aggressive chemical corrosion, and drastically lower long-term maintenance costs. The increasing capital investment in advanced material research is expected to further solidify FRP as a vital, innovative alternative for future infrastructure projects worldwide.

End Use Dynamics and the Rise of Cleaner Alternatives

The end-use segmentation highlights a global market currently in deep transition. Crude oil storage continues to represent the largest individual share of the market, rooted in deep-seated, consistent global demand and vast, pre-existing international infrastructure networks.

However, a pronounced structural shift is occurring as energy demands transition steadily toward cleaner alternatives. Natural gas has established itself as a dominant force, benefiting immensely from extensive new infrastructure projects and its critical role as a transitional bridging fuel. Within this specific spectrum, Liquefied Natural Gas (LNG) is explicitly identified as the fastest-growing end-use category, propelled by its increasing popularity as both a heavy industrial energy source and a high-efficiency maritime transportation fuel. Conversely, the refined products segment faces emerging structural challenges. While still fundamentally essential, its long-term growth is tempered by the accelerating global shifts toward vehicle electrification and zero-emission alternative fuels, forcing operators to pivot and innovate to retain market relevance.

In-Depth Regional Market Analysis 

The geographical distribution of the oil and gas storage market is highly varied, with each macro-region presenting uniquely complex economic drivers, political constraints, and investment opportunities.

North America stands as the undeniable leader in the global market, controlling approximately 40% of the total market share. This massive economic footprint is supported by incredibly robust, well-established historical infrastructure, immense domestic energy demand, and highly favorable regulatory frameworks that aggressively support both traditional hydrocarbons and renewable energy storage developments. The region’s intense strategic focus on maintaining unparalleled national energy security ensures its continued infrastructure dominance throughout the forecast period.

Europe currently holds the second-largest global share, accounting for roughly 30% of the market. The European market is distinctively characterized by its rapid, aggressive transition toward sustainable, low-carbon energy. Guided by powerful, binding regulatory initiatives such as the European Union’s Green Deal, the region is pioneering the massive integration of renewable energy sources and innovative, low-emission storage technologies.

The Asia-Pacific region represents the most economically dynamic and fastest-growing territory, currently holding about 25% of the global market share. Driven by skyrocketing basic energy consumption, highly rapid urbanization, and massive industrial expansion particularly within highly populated emerging Asian economies the region requires vast new greenfield storage capacities. Governments across the Asia-Pacific are heavily focused on reducing their historical import dependency by building massive strategic petroleum reserves and establishing secure, highly localized storage infrastructures.

Finally, the Middle East and Africa, currently holding roughly 5% of the global market, provide significant, resource-rich growth opportunities. The region is witnessing a rapid influx of capital investment aimed at diversifying local energy economies and extensively expanding domestic storage capabilities. These expansions are designed to support broad macroeconomic national initiatives, ensuring long-term economic stability and energy security across the region.

Future Outlook and Strategic Conclusion

As the oil and gas storage market progresses relentlessly toward 2035, it is characterized by a delicate, highly strategic balance between fulfilling immediate, traditional global energy requirements and adapting successfully to a rapidly decarbonizing world. With a projected valuation of USD 341.39 USD Billion by 2035 and a solid, dependable CAGR of 3.64%, the sector is anything but structurally stagnant. The long-term future will be definitively shaped by the mass expansion of highly secure underground storage facilities in strategic locations, the widespread implementation of advanced, AI-driven leak detection and environmental monitoring systems, and the crucial deployment of modular, adaptable infrastructure for rapid scaling. By comprehensively embracing technological innovation, shifting toward dynamic hybrid storage models, and complying rigorously with stringent environmental standards, the global market is fundamentally set to remain incredibly robust. Oil & Gas Advancement believes this evolution will successfully facilitate the secure, reliable transition of global energy supplies for the next decade and far beyond.

Badawi welcomed the company’s intention to scale up investments, emphasizing that natural gas exploration remains a cornerstone of the ministry’s long-term strategy to gradually boost domestic production. He noted that the Mediterranean continues to be a focal point for future upstream activity, supported by Egypt’s well-established infrastructure and extensive technical expertise. According to the minister, these strengths position the country to unlock further opportunities in natural gas exploration while fostering partnerships with major international operators. He also reiterated the government’s commitment to maintaining a supportive investment climate, including offering incentives aimed at encouraging increased capital inflows and expediting project development.

Breant, in turn, acknowledged the Ministry of Petroleum’s efforts to strengthen collaboration with global energy firms. He said TotalEnergies considers Egypt a key strategic market and intends to deepen its footprint through expanded investments, particularly in Mediterranean assets where prospects for natural gas exploration remain promising. Both parties underlined the need to accelerate technical coordination and finalize ongoing discussions, with the goal of signing a memorandum of understanding in the near term and moving ahead with joint exploration initiatives.

The latest engagement follows a prior meeting on April 14th, where Badawi and Breant examined TotalEnergies’ plans for increasing investments in Egypt’s Western Mediterranean region, again highlighting the Herodotus Basin. During that session, both sides agreed to work toward a framework cooperation agreement between the Egyptian Natural Gas Holding Company (EGAS) and TotalEnergies in the coming period.

PETRONAS and ENEOS Xplora (“ENEOS”) have reaffirmed their long-standing partnership, first established in 1995, through the signing of definitive agreements formalising ENEOS’ re-entry into Malaysia LNG Tiga Sdn. Bhd. (MLNG Tiga).

Subject to the fulfilment of certain closing conditions, ENEOS will hold a 10 percent equity stake in MLNG Tiga for the next decade, following the expiry of the previous MLNG Tiga Joint Venture Agreement in 2023.

The agreements were signed by PETRONAS Executive Vice President & Chief Executive Officer of Gas & Maritime Business, Datuk Adif Zulkifli and ENEOS Xplora Representative Director and President, Yasuhiko Oshida.

Witnessing the signing ceremony were PETRONAS Senior Vice President, Corporate Strategy, Marina Md Taib and Executive Officer and Senior Vice President and Head of Business Division 1, ENEOS Xplora, Jotaro Tomoeda.

The agreement marks a significant milestone in the enduring partnership between PETRONAS and ENEOS, reflecting shared commitment to strengthening long-term energy security and supporting reliable LNG supply to international markets, particularly Japan, amid an increasingly complex and volatile global energy landscape.

“LNG continues to play an indispensable role in the global energy mix, bridging the demands of today’s economies while supporting a credible transition toward lower-carbon futures. With Asia at the centre of global LNG demand growth, stable supply and long-term partnerships remain fundamental to economic resilience across the region. The collaboration with ENEOS which now spans three decades reflects that long-term conviction, one that continues to serve the energy interests of both nations well into the decades ahead,” said PETRONAS President and Group Chief Executive Officer Tan Sri Tengku Muhammad Taufik.

ENEOS’ re-entry underscores continued confidence in MLNG Tiga’s operational resilience and long-term value proposition, as well as PETRONAS’ proven capabilities as a world-class LNG operator and trusted partner.

“ENEOS’ re-entry into MLNG Tiga reflects shared confidence in the asset’s resilience and long-term role within Asia’s LNG landscape. It also reinforces PETRONAS’ focus on building a reliable LNG system that continues to deliver value to customers and partners, particularly in important markets such as Japan,” said Adif Zulkifli.

“MLNG Tiga has been a project that has steadily supplied LNG to Japanese buyers since commencing operations in 2003, under the cooperation between our group and PETRONAS, and we are very pleased to be participating once again. While further strengthening our partnership with PETRONAS, we will also work closely with our fellow shareholders – the Sarawak State Government and Mitsubishi Corporation, to pursue new value creation during the energy transition.” said Yasuhiko Oshida.

The agreement reinforces continued foreign investor confidence in Malaysia’s investment climate and long-term growth prospects. This reflects the country’s strong fundamentals, supported by a stable regulatory framework and a conducive business environment that continues to attract long-term investments in the energy sector.

The Bridger Pipeline Expansion, a three-foot-wide conduit, is designed to move as much as 550,000 barrels of oil daily. The planned route begins at the Canadian border in Montana and continues through eastern Montana and Wyoming, where it will connect with an existing pipeline network. Before construction can commence, the project will require further environmental clearances from both state and federal authorities. Company officials anticipate beginning construction next year.

Environmental organizations have voiced opposition to the project, citing concerns about the potential for pipeline ruptures and subsequent spills. At its maximum capacity, the 650-mile pipeline would transport two-thirds of the volume of oil carried by the more widely recognized Keystone XL pipeline. The Keystone XL project’s permit was revoked by President Joe Biden in 2021, citing climate change concerns.

In contrast to the previous administration’s stance on pipeline projects, President Trump stated following the signing of the cross-border approval for the Bridger Pipeline Expansion, “Slightly different from the last administration. They wouldn’t sign a pipeline deal. And we have pipelines going up.” This decision reflects a differing approach to energy infrastructure development.

The Bridger Pipeline Expansion is sometimes referred to as “Keystone Light.” A notable aspect of this project is that it will not traverse any Native American reservations. Bridger Pipeline LLC has stated that over 70% of the pipeline will be constructed within existing pipeline corridors, and approximately 80% will be located on private land. The Casper, Wyoming-based company currently manages over 3,700 miles of oil gathering and transmission pipelines across various basins in North Dakota, Montana, and Wyoming.

Bridger Pipeline, a subsidiary of True Companies, could potentially safeguard its project from future policy reversals by a subsequent administration if construction is completed before the end of President Trump’s current term. The company’s timeline projects construction starting in the fall of 2027, with completion anticipated by late 2028 or early 2029, aligning with the end of President Trump’s term in January 2029.

The total consideration for the transaction will be the sum of R$ 700 million and US$ 150 million, with payment expected to be made in three installments, as follows: (i) the first installment, in the amount of R$ 100 million, upon closing of the transaction (“Closing”) (ii) the second installment, in the amount of R$ 600 million, on January 15, 2027 or at Closing, whichever occurs later and (iii) the third installment, in the amount of US$ 150 million, two years after Closing. The amounts are subject to price adjustments as defined in the agreement.

Upon completion of the transaction, Petrobras will hold a 98.11% interest in the Jubarte Shared Reservoir, while the Federal Government, represented by Pré-Sal Petróleo S.A. (“PPSA”), will maintain its 1.89% interest related to the extension of the reservoir into non-contracted areas. In addition, upon closing of the transaction, the negotiation process for equalization among Petrobras, Shell, ONGC, and Brava whose progress was disclosed in a release dated October 20, 2025  be concluded, as will any ongoing or potential negotiations related to unitization of production and/or equalization of any shared reservoirs between Jubarte and the portion of the ring-fence subject to this transaction.

The acquisition offers attractive economic and financial terms, simplifies asset management, and is aligned with Petrobras’ Business Plan, strengthening our operations in the Campos Basin and maximizing value with a focus on profitable assets.

Closing of the transaction is subject to the satisfaction of conditions precedent set forth in the purchase and sale agreement, including approval by the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis – “ANP”) and the Administrative Council for Economic Defense (Conselho Administrativo de Defesa Econômica – “CADE”).

About Parque das Baleias

The Jubarte Shared Reservoir is operated by Petrobras in an integrated manner with the production infrastructure of the area known as Parque das Baleias. Parque das Baleias is a group of fields located in the northern portion of the Campos Basin, in water depths between approximately 1,220 and 1,400 meters, with Jubarte as its main field. The assets are operated by Petrobras through the P-57 and P-58 platforms, the FPSO Cidade de Anchieta, and the FPSO Maria Quitéria, with current production of approximately 210 thousand barrels of oil per day.

The deal comes as Venezuela accelerates efforts to attract foreign investment into its energy sector, having recently concluded exploration and cooperation agreements with global producers such as Italy’s Eni and Spain’s Repsol. This shift follows the ouster of President Nicolas Maduro by U.S. forces in January, a development that has opened the door for broader international participation in the country’s oil and gas industry. Within this evolving landscape, BP is positioning itself as a key participant in cross-border gas initiatives tied to regional supply and export infrastructure.

Speaking at the signing ceremony, Venezuela’s interim President Delcy Rodriguez, said, “The return of BP is a ⁠clear sign of the future we want to chart for Venezuela and for ​international energy relations — relationships based on respect, cooperation grounded in a win-win approach, and ​shared benefits that contribute to the development of the Venezuelan people.”

William Lin, BP’s executive vice president for gas and low carbon energy, said the company was pleased to be partners with Venezuela on the exploration of the Loran area, as well as on other projects, ‌including ⁠the commercialization of gas.

The MOU also “formalized the launch of gas development at the Cocuina-Manakin field,” a gas field that crosses the border between Trinidad and Tobago and Venezuela, Rodriguez’s office said in ​a statement.

The field straddles the border between Venezuela and Trinidad and Tobago, with Cocuina forming part of the inactive Deltana Platform project on the Venezuelan side and extending into Trinidad, where a BP subsidiary operates it as Block 5b.

BP had earlier indicated it was seeking a U.S. government license to move ahead with development of the Cocuina-Manakin field. The company aims to unlock more than 1 trillion cubic feet of gas from the project, which would be transported to Trinidad for conversion into liquefied natural gas destined for export markets.

In response, U.S. LNG exporters have ramped up operations, maximising liquefaction capacity and tightening vessel loading schedules to increase shipment volumes. Data from Kpler show U.S. LNG exports are estimated to reach a record 32.15 million metric tonnes between January and April 2026, marking a 28% rise compared with the same period last year. This roughly 7 million-tonne increase has more than compensated for Qatar’s decline of 6.93 million tonnes during the same timeframe. Consequently, total global seaborne LNG exports are projected to exceed 149 million tonnes in the first four months of 2026, reflecting a 6% year-on-year increase, with U.S. LNG exports accounting for a record 18% share.

Operationally, Cheniere Energy’s Sabine Pass terminal in Louisiana continues to serve as the central hub for U.S. LNG exports, managing about 25% of shipments in the first quarter. Meanwhile, Venture Global’s Plaquemines LNG terminal has played a pivotal role in driving growth, with export volumes surging 240% year on year. The facility shipped nearly 6.5 million tonnes of LNG in the first quarter of 2026, compared with less than 2 million tonnes a year earlier. Despite this strong performance, sustaining such output levels may prove challenging. Routine maintenance requirements, along with risks linked to extreme weather and the approaching hurricane season in early summer, could disrupt operations and slow export momentum.

Europe has emerged as the dominant destination for U.S. cargoes, accounting for around 72% of shipments in 2026, with nine of the top ten buyers located in the region. Although seasonal demand typically eases as temperatures rise, storage levels remain low at approximately 30% following the winter season. This suggests that replenishment needs ahead of the next winter could continue to underpin demand for U.S. LNG exports, even as broader market conditions evolve.

The departure is effective in just days and removes 4.8 million barrels per day of production capacity from the OPEC+ coordination framework, a capacity that Abu Dhabi’s national oil company, Adnoc, now intends to deploy without quota constraints.

The timing of this decision is not incidental. Three converging structural factors shaped the UAE’s move.

The most immediate driver is capacity expansion. Adnoc’s US$150 billion investment programme has accelerated the UAE’s production ramp-up significantly. The 5 million barrels per day target, previously set for 2030, has now been pulled forward to 2027, three full years ahead of schedule. Inside the OPEC+ quota system, the UAE has been producing approximately 30 percent below its current capacity, a constraint that has grown increasingly difficult to justify as infrastructure investment matures.

The second driver is the current market disruption stemming from the Iran war. OPEC production fell 27 percent to 20.79 million bpd in March 2026, the largest supply collapse on record. The Hormuz crisis has created a substantial demand gap in global supply. For Abu Dhabi, operating outside a quota framework means Adnoc can move directly to fill that gap rather than waiting for coordinated OPEC+ decisions.

The third driver is longer-term demand trajectory. The UAE’s decision reflects that calculus directly. It wants to maximise output and revenue now, rather than defer to cartel discipline.

The exit of the UAE deals a significant structural blow to OPEC’s market coordination authority. The country represents approximately 4 percent of total global oil production and has historically been one of three Gulf swing-producer pillars alongside Saudi Arabia and Iraq.

This is not the first Gulf state exit. Qatar departed OPEC in 2019, citing its identity as a gas-focused economy where OPEC membership had become increasingly irrelevant. Bahrain and Oman remain outside OPEC but continue to participate in supply coordination informally. The broader pattern that emerges is clear: Gulf producers beyond Saudi Arabia and Iraq are progressively distancing themselves from the OPEC framework.

With the UAE’s departure, Saudi Arabia and Iraq stand as the only remaining major OPEC producers in the Gulf. The cartel’s credibility as a unified pricing bloc is now under direct pressure from within its own region.

Riyadh now faces the full weight of OPEC market discipline without one of its most significant partners. Saudi Arabia, with a 12 million barrels per day capacity target, has historically been the cartel’s anchor of supply discipline. That role becomes considerably more difficult when a neighbouring producer of the UAE’s scale operates freely outside the quota system.

The UAE-Saudi competitive dynamic has been building for years. Both countries target overlapping Asian export markets, operate in adjacent waters, and both have large sovereign wealth funds with similar regional investment mandates. Political tensions also surfaced late last year when Saudi Arabia bombed weapons shipments bound for UAE-backed separatist forces in Yemen, a visible sign of a fracturing relationship.

Saudi Crown Prince Mohammed bin Salman now faces a difficult set of choices: absorb the burden of production discipline alone, match UAE output increases and accept global oversupply, or seek bilateral arrangements with Abu Dhabi outside the OPEC structure. The OPEC meeting scheduled for Wednesday in Vienna has taken on considerably greater strategic significance in this context.

For Latin American oil exporters , none of whom are OPEC members, a less coordinated OPEC creates meaningful market share opportunities.

Brazil’s Petrobras stands to benefit most directly, with pre-salt production growing toward 4 million barrels per day by 2030 and the Argonauta acquisition in progress. Argentina’s YPF is accelerating Vaca Muerta development under the government’s RIGI incentive framework. Colombia’s Ecopetrol continues to export at strong margins despite structural output declines. Venezuela’s PDVSA is restarting production under US oil revenue audit oversight.

Mexico, however, faces a more challenging outlook. Pemex’s already-declining production sits against a medium-term backdrop of weakening OPEC supply discipline and increasing global supply. Given that Mexico is the third-largest supplier of oil to the United States, shifts in global pricing dynamics carry direct implications for US-Mexico energy trade.

For businesses operating across the energy supply chain , from upstream E&P companies to refiners, traders, and logistics providers, UAE’s OPEC exit comes at a moment that creates simultaneous bearish and bullish pressures.

The near-term outlook remains constructive for prices. Brent crude was trading above US$110 per barrel at the time of the announcement, supported by Hormuz disruption and the broader Iran war. The World Bank’s Commodity Markets Outlook, published on the same day, projected 2026 energy prices to surge 24 percent on the back of the conflict. As long as the Hormuz crisis persists, the UAE’s incremental barrels will take time to reach markets regardless of quota freedom.

“ARC is a high-quality, low-cost and top quartile low carbon intensity producer operating in the Montney shale basin that complements our existing footprint in Canada and strengthens our resource base for decades to come. We are accessing uniquely positioned assets and welcoming colleagues that bring deep expertise which, combined with Shell’s strong basin level performance, provides a compelling proposition for shareholders.” said Shell’s chief executive officer, Wael Sawan. “This establishes Canada as a heartland for Shell while furthering our strategy to deliver more value with less emissions.”

“This combination is a great opportunity for ARC to realise value for our shareholders and continue to benefit from Shell’s success in the future. ARC is combining with a company that has a global portfolio of best-in-class assets,” said ARC president and CEO, Terry Anderson. “I’m excited that ARC’s assets and world class people will play an important role in helping Shell to further strengthen Canada’s resource landscape whilst also providing the secure energy that the world needs.”

This ARC Resources acquisition increases Shell’s production CAGR from 1% as outlined at our 2025 Capital Market’s Day to 4%3, compared to 2025, and supports Shell’s aim to sustain material liquids production of ~1.4 million barrels per day towards 2030 and beyond. The transaction combines ARC’s more than 1.5 million net acres with Shell’s ~440 thousand net acres in the Montney formation and adds ~2 billion barrels of oil equivalent proved plus probable reserves at the end of 20254. Last year, ~40 per cent of ARC’s production was liquids, which accounted for ~70 per cent of its revenues. In addition, ARC’s proved plus probable gas reserves have the potential to support Shell’s growth in LNG in Canada.

Under the terms of the agreement, ARC’s shareholders will receive CAD 8.20 in cash and 0.40247 ordinary shares of Shell for each ARC share, representing approximately 25% cash and 75% shares as of the 24th April 2026 market closing. Based on Shell’s closing share price on this date of GBP 33.08 and GBP:CAD exchange ratio of 1.8480, this translates to a consideration of CAD 32.80 per share, which represents a 20 per cent premium to ARC’s 30-day5 VWAP. This equates to an equity value of approximately US$13.6 billion. Shell will take on approximately US$2.8 billion in net debt and leases resulting in an enterprise value of approximately US$16.4 billion. The equity value of US$13.6 billion will be funded via US$3.4 billion in cash and US$10.2 billion in Shell shares, the latter valued based on Shell’s closing price on the 24th April and the issuance of approximately 228 million ordinary shares.

The boards of both companies have unanimously supported the transaction, which is expected to close in the second half of 2026, subject to ARC shareholder, court and regulatory approvals.

Enbridge has been advancing its Sunrise Expansion project since 2022, aiming to increase natural gas capacity in British Columbia by 300 million cubic feet per day. The company submitted its federal regulatory application two years ago. According to Matthew Akman, the company’s president of gas transmission and midstream, the approval process for this Enbridge gas pipeline expansion moved faster than previous projects. However, he emphasized that Canada still needs to accelerate approvals further to remain competitive in global energy export markets and liquefied natural gas developments.

The Enbridge gas pipeline expansion is intended to address growing natural gas demand in British Columbia, particularly from LNG developments such as Woodfibre LNG, which is currently under construction on the Pacific coast and in which Enbridge holds a 30% stake.

“From our experience, because we do these things on both sides of the border, the U.S. is moving faster,” Akman said, adding Enbridge thinks Canada’s LNG potential could support construction of two or three more large gas pipelines to the Pacific coast. The company’s Westcoast pipeline network spans 2,900 kilometers (1,802 miles) from northeast British Columbia to the Canada-U.S. border, with an existing capacity of 3.6 billion cubic feet of natural gas per day.

The project scope includes the construction of new pipeline segments alongside the current system, the addition of gas compression capacity, and upgrades to existing infrastructure. Construction activities related to the Enbridge gas pipeline expansion are expected to begin in July, with operations targeted to commence in late 2028.