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Energy Insights 2026

EXECUTIVE SUMMARY

Kenneth B. Medlock III Senior Director, Center for Energy Studies and James A. Baker, III and Susan G. Baker Fellow in Energy and Resource Economics

Given the state of the global energy landscape, Energy Insights 2026 covers a lot of ground. Energy security, resilience, affordability, and pragmatism all reign supreme in energy policy discourse. Just a decade ago these concepts were not at the forefront of energy economics and policy discourse, but the pendulum continues to swing. The state of politics around the world seems to be exacerbating this. But certain truths are unavoidable. In Energy Insights 2025, a very basic point was raised, “There is no economic model where adding a constraint lowers cost.” Policy interventions and geopolitical events create arbitrage opportunities. Market participants always try to find ways to trade around changes or disruptions, and market liquidity facilitates success. This, in turn, highlights the importance of real option value. When an asset can generate very high value during times of extreme volatility, that value can drive investment, even if the asset generates very little value otherwise. By simply existing, the asset provides a monetizable option that raises overall supply chain resilience. We are seeing countries and companies around the world internalize this point in the wake of the disruption of commodity movements through the Strait of Hormuz by announcing investment in new sources of supply, new pipelines, and new refineries. Diversification is the word of 2026. Energy Insights 2026 opens by running a chapter from last year’s edition – Energy Security and Supply Chain Resilience. As we are seeing currently, this chapter highlights that energy security is best framed as supply chain resilience, not self-sufficiency. This point is sometimes lost, especially when the idea of export bans is raised, but the law of unintended consequences can bite hard. Market depth and fungibility have historically been the best harbingers of stability, but this requires diversified trade networks, redundant supply options (including storage), and regulatory certainty. If policy can reduce uncertainty, it can unlock capital that deepens markets and builds resilience. Energy Insights 2026

In Without Supply Chains for Fuels, The World Stops, Ed Emmett reinforces the basic point that supply chain resilience is vital for global economic activity. After all, the transportation network that is the circulatory system of the global economy, and it relies on fuels to distribute goods around the world. Absent those fuels, the economy grinds to a halt. Unfortunately, as noted in Mid-2026 Global Oil market Outlook: Iran Conflict to Have a Lasting Impact, Abhi Rajendran and Skip York note that there is a winding road ahead before energy markets calm, and a substantial amount of investment is already occurring. This will lead to a very different global oil market. In The Year of the ‘Shock’, Ken Medlock breaks down previous energy price shocks and evaluates market responses to each. This leads to a conclusion that the risks exposed by the conflict in the Middle East will drive substantial investment in the region and abroad. Returns on investment will still matter, but the risk-reward framework is now different. Some of the commercial approaches historically taken to secure supply chains will find their way more deeply into macro-level policy. In the end, this will drive a more resilient future. Stepping into the Middle East, in Qatar’s Iran Problem, Jim Krane discusses the issues that Qatar faces as it navigates the path ahead, particularly given its dependence on the Strait of Hormuz to move LNG. In The GCC Post-War Strategy for Import/Export Resilience, Salem Alhajraf expands to the entire region to highlight how GCC members are likely to recalculate options for connectivity to the rest of the world, diversifying away from the Strait of Hormuz where possible. Gabe Arrington and Chris Bronk each, respectively, tackle issues related to infrastructure, AI and security. In Airspace Sovereignty Comes to Energy Infrastructure, Gabe presents the argument that the security of energy infrastructure must be engaged in three dimensions because the “fence line” now extends upward. As such, policy needs to shift to recognize the critical intersection of energy security and governance of air space around it. In AI, Energy, and an Evolving Cybersecurity Landscape, Chris argues that the energy and cybersecurity landscape is evolving rapidly, calling on the last 15 years of research into this space. He lays out the case for organizations to combine the very best of human talent with cyber tools in order to better secure the infrastructure that underpins modern life. Of course, minerals and metals markets continue to evolve, with growing demands and increasing government engagement aimed at developing and deepening supply chains that are critical for defense, national security, and electrification.

Executive Summary

In The Hidden Constraints on Critical Minerals Finance, Ashley Zumwalt-Forbes addresses critical minerals and their governance, sources of government capital for development and how they have evolved through the past three US administrations, and what is needed to drive greater private investment. In From Rocks to Renewables, Osmel Manzano and Daniela Valdivia argue that energy transitions are actually extractive transitions, and that institutions, rather resources, could constrain the pace and scale of change. They also highlight lessons to be taken from the experience of oil and the importance of community engagement for successful development of the mining and extractives industries. Latin America is a virtual hotbed of resource development opportunities, from oil to gas to metal and minerals. So, the region has strategic importance for the future of multiple energy sources and their competitiveness in an evolving global energy landscape. In National Oil Companies and Latin America's Oil Boom, Francisco Monaldi investigates the effect of NOCs on regional growth, contrasting the trajectories of different countries with very different resource production paradigms. The existence of an NOC need not translate to suboptimal development, but the lure of resource rents has historically had negative implications for sustained investment across the region. As such, the future will very much be shaped by whether or not countries’ governments can act in the best interest of sustaining long-term investments in the resource industries. In The Rise of Neuquén, Mark Jones dives into regional politics in Argentina, connecting it to the recent successes of development in the Vaca Muerta. He notes that regional governance is very important for sustained capital inflow and production growth, even if national elections swing away from the incumbent party. In Unlocking the Potential for an Energy Revolution in Latin America and the Caribbean, Lourdes Melgar highlights the ongoing conflicts in Ukraine and Iran, the political uncertainty in Latin America triggered by a shift in US policy toward the region, and what each means for energy security policy. She argues that it is “important to design and implement stable and resilient institutions, predictable legal and regulatory frameworks, and state-of-the-art policies that enable moving beyond failed models of the past.” Doing so requires developing regional supply chain resilience that has been missing, but it could drive the region to become a 21st century industrial leader. Electricity remains a stalwart in global energy conversations largely because it remains mired in working through the tradeoffs associated with transitioning energy sources, grid expansion, and cost.

Energy Insights 2026

Kenneth B. Medlock III

In Power Sector Challenges, Peter Hartley highlights the problems with using levelized costs of electricity (LCOE) to inform policy and draws on experiences in different markets as evidence. He concludes by emphasizing the importance of full system cost-benefit analysis, with reference to the conflict in the Middle East, energy security priorities, the dominance of critical minerals supply chains by China, and the challenge faced by grids with increasing variable energy sources. Julie Cohn addresses two issues that the electricity industry faces as demand expands and grid needs grow in Booming Energy Demand and Becoming Standard. In the former, she draws on history as a teacher, referencing the experiences around World War II, the anticipated load growth during that time, and the policy responses to deal with it. She also emphasizes the need to look more deeply at past experiences to help guide future outcomes. In the latter chapter, Julie addresses the work of the Universal Interoperability for Grid-forming Inverters Consortium, which is focused on the very real engineering challenges associated with integrating new, non-spinning variable power generation technologies into the electric power grid. Solutions will ultimately link to policies around grid interconnection, exploring on a case-by-case basis the most efficient approach to promoting grid stability, and codifying the integration of very large loads into an evolving grid. In Competitive Retail Electricity Markets, Tilsa Oré Monago examines retail choice in Texas. She points out that the health of the competitive market depends on both the number of retail service providers and consumer willingness to switch. This has implications for regulatory oversight and, ultimately, the price paid. Brand loyalty can come with a premium. Turning to Asia, Gabe Collins and Henry Haggard examine the response to energy shocks across several countries. In What Lessons Did China and India Learn from the Last Great Global Energy Shock?, Gabe notes that China and India have pursued very different strategies. He argues that China has learned to pursue a strategy of self-reliance and electrification, while India has learned that energy shocks ripple through food and household welfare. Interestingly, the implication is that both countries will lean into domestic coal resources to accomplish their energy security objectives, which will have global energy market ramifications well into the future. In Japan, Korea, and a Fifty-Year Education in Energy Vulnerability, Henry leans into the collective experiences of two highly import dependent developed economies – Japan and Korea. He uses history to explore what the ramification of the Hormuz crisis will be, arguing that the US will play a significant role, as it has in the past. Namely, there is an open question about how the current crisis will shape future decisions. 05

Executive Summary

Will it shift the procurement practices of these countries and have lasting implications for supply chains in Asia, or will the past reassert itself as the crisis abates? Time will tell, but the case for the former has never been stronger. Next, the attention turns to Europe, where the impacts of multiple conflicts have altered discussions around energy. In An Energy Tour of the Balkans, Ted Loch-Temzelides highlights the diversity and historical complexity of the region, which has massive implications for politics, investment and the energy sector. There are multiple points of access to the region, from Turkey to the Russia to the Eastern Mediterranean, but there remains concerns about over-reliance on any of these options. This points to a strategy of diversification, but it could also spell growing tensions with the EU. In Limits and Consequences of Sanctions on Russian Energy, Raúl Bajo-Buenestado discusses sanctions policies on energy from Russia. For Europe, this is complicated by the depth to which Russia has historically been integrated into EU energy networks. While sanctions policy can reshape flows, they also carry secondary impacts that mitigate their full impact. Global markets are fungible, and they adjust to interventions. Hence, harkening back to old question, if sanctions ultimately only adjust trade routes rather than limit trade, what is their impact, and are they worth it? This is something that countries in the EU will forced to grapple with as time passes. In Europe’s Elusive Energy Security Equation, Anna Mikulska expands on the dependency question in Europe, referencing a cartoon circulating on LinkedIn that depicts a wheel of fortune with American, Russian, and Qatari flags, with the caption “please spin the wheel on who will determine the price of your heating this winter.” This basic, but powerful imagery captures a mood that is pervasive across the EU. She then discusses various issues at play and concludes by noting that the “variables of the equation are known—diversified suppliers, redundant infrastructure, contracted volumes, and a public conversation honest enough to permit all three.” To wrap this year’s discussions on Europe, Michał Kurtyka argues in What Went Wrong with the European Energy Transition? that 2022 was a turning point in the conversation about energy in the EU. Namely, energy security moved to the top of the docket. Working though the a litany of issues, he ultimately concludes that a successful energy transition will come not from targets and regulation, but from focusing on technological realism, competition, and grounded geopolitical strategy.

Energy Insights 2026

Kenneth B. Medlock III

Energy Insights 2026 closes with contributions focused on sustainability, specifically with regard to circularity in the plastics industry. In From Circularity to Resilience: Plastics as a Strategic Resource, Rachel Meidl reframes the discussion on plastics from one of waste and pollution to one of a strategic resource. The disruption created by the closing of the Strait of Hormuz has rippled well beyond just the price at the pump. It has impacted many aspects of modern life. In many ways, the role of plastics is often misunderstood, largely because they are so ubiquitous in modern life. Accordingly, anything that threatens the supply chain has massive ramifications. One path to overcoming this is by developing costeffective circular pathways that reinforce supply chain resilience. In Beyond the Loop: Creating an Adaptive Circular Network for Plastics, Jackie deGroot roots the plastics discussion in a transitional moment: will a next-generation framework for circular pathways be established, or will the status quo persist. Innovation across the technology, process and regulatory space have elevated the opportunity for the former, but legal architectures, public perceptions and politics present challenges. She ends by presenting a framework for advancing a next generation solution, and argues that successful implementation requires much broader, holistic thinking. Energy Insights 2026 ends much like it begins, with a call back to Energy Insights 2025, An Enduring Emphasis on Resilience shows that damages from natural disasters are an increasing part of the larger media narrative. This, in turn, drives perceptions that don’t always align with historical data, which reveal that increasing damages are driven less by disaster frequency and more by population growth and urban expansion. They use the Natural Disaster Resilience dashboard to highlight examples, and they argue for adaptive measures—such as stronger building codes, more diligent land-use planning, and commercially sustainable insurance frameworks—that reduce vulnerability regardless of climate outcomes. Efforts to decarbonize are not disappearing, but they must be paired with adaptive resilience because natural disasters will occur even in a lower carbon future. CES fellows and scholars will continue to advance research in effort to elevate discussions about the future of energy. Tradeoffs are ever-present, and approaches that are grounded in economic fundamentals, a deep understanding of political economy, and rigor in data analysis can help to navigate uncertainties. To that end, Energy Insights 2026 offers a glimpse of ongoing research and CES initiatives.

TABLE OF CONTENTS Energy Security and Supply Chain Resilience

Without Supply Chains for Fuels, the World Stops

Mid-2026 Global Oil Market Outlook: Iran Conflict To Have a Lasting Impact

The Year of the ‘Shock’

Qatar’s Iran Problem: Maintaining LNG Exports Through Tehran’s Chokepoint

The GCC Post-War Strategy for Import and Export Resilience Network

Airspace Sovereignty Comes to Energy Infrastructure: The 2026 Counter-UAS Inflection Point

AI, Energy, and an Evolving Cybersecurity Landscape

The Hidden Constraints on Critical Minerals Finance

From Rocks to Renewables: Will Critical Minerals Constrain the Energy Transition?

National Oil Companies and Latin America’s Oil Boom: Catalysts or Constraints?

103

The Rise of Neuquén to Preeminent Petro-Province Status and the Governor Who is on Track To Lead It Through 2031

116

Unlocking the Potential for an Energy Revolution in Latin America and the Caribbean

122

Power Sector Challenges

131

Booming Energy Demand: World War II vs Data Centers

140

Becoming Standard: Grid-Forming Inverters on All Sides of the Meter

149

Competitive Retail Electricity Markets and Consumer Switching in Texas

158

What Lessons Did China and India Learn From the Last Great Global Energy Shock?

168

Japan, Korea, and a Fifty-Year Education in Energy Vulnerability

177

An Energy Tour of the Balkans

187

Limits and Consequences of Sanctions on Russian Energy Products

195

Europe’s Elusive Energy Security Equation

205

What Went Wrong With the European Energy Transition?

217

From Circularity to Resilience: Plastics as a Strategic Resource

231

Beyond the Loop: Creating an Adaptive Circular Network for Plastics

238

An Enduring Emphasis on Resilience

246

SUSTAINABILITY AND RESILIENCE

Energy Security and Supply Chain Resilience ‘Run It Back’ from Energy Insights 2025 Kenneth B. Medlock III CES Senior Director | James A. Baker, III and Susan G. Baker Fellow in Energy and Resource Economics

Article Preface: A Context for Current Policy Discussions On February 28, 2026, US and Israel launched coordinated strikes on Iran. Shortly after, the global maritime insurance industry announced it would not cover war-related risks, which resulted in a suspension of traffic through the Strait of Hormuz. The de facto closure of the Strait due to the credible threat of Iran’s ability to kinetically intercede is a real time example of game theory in practice. But, more importantly, it resulted in a massive disruption of supply chains for oil, petroleum products, LNG, ammonia, helium, etc. In turn, the role of supply chain resilience for achieving energy security has pushed to the forefront of global policy dialogue. This has long been a central theme of research at the Baker Institute Center for Energy Studies, with a very recent example published in last year’s Energy Insights 2025.

A Brief Discussion of Energy Security, Research, and Policy in the US The question of how to achieve energy security has been explored extensively by policymakers, academics, and energy analysts, and it has been at the core of U.S. energy policy since at least the early 1970s. The concept of energy security became a centerpiece of energy policy discourse following the oil price shocks of the 1970s.

Energy Security and Supply Chain Resilience

A negative correlation between oil price and macroeconomic performance in oil-importing countries — highlighted by the fact that most recessions in oil-importing countries since World War II have been preceded by a run-up in the price of oil — has prompted interest in designing policies to mitigate any negative impact of rising oil prices. In this context, “energy security” generally refers to the concept of ensuring an adequate supply of energy at a stable and reasonable price, thus leaving us with three basic tenets to achieving energy security: adequacy, stability, and reasonableness.1 While there have been various proposed definitions of energy security, at its core, energy security is about avoiding the macroeconomic dislocations (i.e., economic downturns) associated with unexpected spikes in energy price or disruptions in energy supply. Multiple policy interventions have advanced through the years in attempts to achieve this goal, to varying degrees of success.2 Figure 1 indicates the monthly spot price of oil from January 1950 through December 2024, along with National Bureau of Economic Research-indicated recessions in the U.S.3 The causes of past recessions are well-documented, with only a few being explicitly linked to oil prices, but it is inescapable that nine of the eleven recessions from 1950 to 2024 were preceded by an increase in the price of oil.4 This correlation has been the subject of much research, and it has been at the core of broader policy discourse about energy security, especially since the early 1970s. Research on the link between energy price and the economy consistently reveals a negative relationship. Most often, research focuses on oil price as a proxy for energy price. This is typically done because energy prices are cointegrated, so they tend to move together, even with some periodic instability.5 This, plus the simple matter of data availability, global fungibility, and the fact that petroleum product prices are posted publicly on street corners across America, is why oil price is often the focus of both academicians and policymakers. One of the most cited of previous academic explorations is James D. Hamilton’s 1983 study, which presented compelling statistical evidence that oil price shocks are a contributing factor to U.S. recessions.6 Since then, a lot of research has focused on the factors responsible for the link between oil price and the macroeconomy.7 The topic has also been extended to other economies, expanded to include the effects of unexpected shocks and price volatility, and openly debated in the academic literature.8 The continuing interest reflects a topic that remains top-of-mind.

Energy Insights 2026

Kenneth B. Medlock III

Figure 1 — Monthly Oil Price and NBER Recessions, 1950–2024

Sources: US Federal Reserve Database and National Bureau of Economic Research. Note: to the oil price indicated is West Texas Intermediate (WTI).

The mounting concerns about energy security in the early 1970s that triggered such significant research interests were not arbitrary. Imports of crude oil had steadily increased since the early 1950s and, in 1959, the Mandatory Oil Import Quota Program was established by President Dwight D. Eisenhower to prevent U.S. dependence on foreign sources of oil.9 In 1973, President Richard Nixon ended the program because foreign crude oil had become cheaper than domestic crude oil. But the Arab oil embargo of late 1973 triggered a significant reorientation of policy. Through the 1970s, policy tilted to favor domestic coal, largely because the U.S. held a dominant position with about one-quarter of global recoverable resource and was not dependent on imports. For example, the Energy Supply and Environmental Coordination Act of 1974 required that new power plants be able to use coal,8 and the Energy Policy and Conservation Act of 1975 authorized loan guarantees for new underground mines.10 As might be expected, coal use in the U.S. almost doubled over the following 20 years. 13

Energy Security and Supply Chain Resilience

Policy also pushed for technologies — such as nuclear, wind, and solar — that were considered immune from hegemonic foreign action, and there was action aimed at developing emergency oil stocks with the Strategic Petroleum Reserve. In addition, efficiency mandates with Corporate Average Fuel Economy (CAFE) standards and new commercial building codes were adopted, a ban on oil exports was put in place, restrictions were levied on new natural gas-fired power generation capacity, and there was a push for the development of Arctic resources, which included the construction of the trans-Alaska pipeline. There was also an examination of resource opportunities on the outer continental shelf10 and a revamp of natural gas regulations with the Natural Gas Policy Act of 1978.11 While several of these actions have since been either undone or have become a point of contentious political debate, when they were considered there was widespread support. In fact, in 1987, at the request of the secretary of energy, the National Petroleum Council examined the state of energy markets and encouraged new federal interventions.12 The desired end-state? Self-sufficiency. Of course, the story does not end in the late 1980s. Several additional policy interventions have occurred since the late 1980s, highlighted by things such as: Energy Policy Act of 2005.13 Energy Independence and Security Act of 2007.14 American Recovery and Reinvestment Act of 2009.15 Lifting of the oil export ban in 2015.16 Infrastructure Investment and Jobs Act of 2021.17 CHIPS Act of 2022.18 Inflation Reduction Act of 2022.19 Among other things, these policies established renewable fuel standards; increased energy efficiency standards for automobiles and appliances; stimulated domestic oil and gas production; advanced measures to more aggressively integrate wind and solar energy resources; and provided incentives for the development of electricity storage, various low carbon energy sources, and carbon capture and sequestration. Most recently, legislation passed under H.R. 1 through reconciliation (a.k.a. the One Big Beautiful Bill Act [OBBBA]) in 2025 reduced or eliminated the incentives for certain types of energy technologies, such as wind and solar, while enhancing or clarifying incentives for others, such as hydrogen, nuclear, geothermal, oil, gas, and carbon capture.20

Energy Insights 2026

Kenneth B. Medlock III

While the above treatment is not meant to be exhaustive, it suffices to indicate that there have been numerous policies adopted over the last 50+ years, initiated from both sides of the political aisle, with the intent of providing ample, low-cost energy to households and businesses. Across the board, this is all in the interest of fortifying energy security. While all political interests align on the end goal, disagreements persist on the path to get there. Ironically, this raises uncertainty, which works against the end goal. However, it is useful to recognize that energy security can only be achieved when supply chains are resilient to unexpected disruptions.

Connecting Supply Chain Resilience and Energy Security A supply chain is characterized by coordination across a diverse set of actors to move a raw material through various stages of production in order to ultimately deliver a final product to a consumer. Hence, a supply chain generally involves raw material production and processing, intermediate production of components and parts, manufacturing and assembly, marketing and distribution at the wholesale level, marketing and distribution at the retail level, and endof-life management (Figure 2). At each step: Analysis is performed to understand regulatory and economic risk and determine an expected commercial return to an activity. Warehousing and inventory management is integrated to smooth out supply-demand imbalances. Transportation and logistics functions are executed to schedule movement of inputs and outputs and increase the diversification of suppliers and off-takers. Counterparty relationships are managed to strengthen engagement and commitment. New technologies are consistently evaluated in effort to improve operational efficiency in a cost-effective manner. Each of these functions must occur in coordination with each other if the supply chain is to develop and operate smoothly and efficiently. A breakdown at any point in the supply chain destroys value at every point in the supply chain.

Energy Security and Supply Chain Resilience

Figure 2 — A Descriptive Supply Chain With Select Critical Elements

Source: Author’s construction.

The various agents along a supply chain understand the outline of Figure 2 intimately because a breakdown of any one of the vital functions can lead to disruptions that compromise commercial viability. As such, firms take steps to ensure the risks of disruption are minimized. Governments can also step into supply chain operations in various ways in an effort to ensure certain risks are mitigated, which can be especially useful if a transaction space along a supply chain lacks transparency, liquidity, and fungibility. But government interventions are typically limited to areas where there is a broader national implication. In general, investments — both public and private — can provide valuable insurance against destabilizing disruptions. At a macro level, understanding supply chains is critical because they are a defining feature of overall economic health. As referenced above, federal level energy policy is often focused on things like expanding domestic energy production, building strategic inventory, or enhancing control of various parts of a supply chain, all in the name of self-sufficiency. But does self-sufficiency equal energy security? No. Security of supply is accomplished by building resilient supply chains. Energy Insights 2026

Kenneth B. Medlock III

This can be accomplished in several ways, including but not limited to greater commercial storage capacity, improved inventory management practices, expanded trading pathways with multiple partners, and increased substitution opportunities.21 Interestingly, there is a common thread that runs through all these pathways. Namely, they all represent arbitrage mechanisms that increase market depth and enhance fungibility. Importantly, greater fungibility allows for more rapid response to unexpected supply chain disruptions. Hence, market depth and fungibility are mechanisms that increase the elasticity of supply, as has been witnessed with the astounding growth of U.S. tight oil and shale gas production, thereby enhancing energy security.22 The U.S. has become a significant exporter of crude oil, petroleum products, and natural gas over the last 15 years, and this new reality is a product of geology and resource endowment, property rights and market institutions, and access to global markets. This has altered the energy security picture in the U.S. But this is explicitly not the same as energy independence or self-sufficiency. Market depth and fungibility have fueled the U.S. role in a new global energy environment, and this has been driven by more connectivity, not less, with multiple trading partners. For long-term growth, there must be mutually beneficial trades that drive investment in infrastructure which, in turn, expands the number of options available to deal with unexpected disruptions. So it is imprudent to separate energy security, market structure, trade, and investment because they are intimately linked. The lesson that commercial actors understand very well — that optionality along supply chains mitigates the risk of coordination failure and brings greater certainty to value creation — translates to broader energy security goals.

Energy Policy Must Evolve The lessons about supply chain resilience are useful for energy policy. As discussed above, the health of a supply chain is linked to market depth and fungibility at each step, and expected commercial returns, regulation, inventory management, and transportation and logistics all play critical roles. Table 1 maps supply chain resilience measures to policy approaches that can enhance energy security. Note that Table 1 provides general approaches rather than specific policies, and is agnostic to energy technology. In application, a specific policy must be designed with the technology in mind. For example, current policy language related to “foreign entities of concern” in the OBBBA directly links to concerns about China’s dominant position in supply chains for solar, wind, and battery technologies.

Energy Security and Supply Chain Resilience

One can argue the effectiveness of the approach, but it is an overt recognition of a need to diversify those supply chains to make them more resilient to potential hegemonic action by China. A similar type of intervention was argued for years with regard to Europe’s reliance on natural gas from Russia, but nothing happened until more recently after the train went off the proverbial tracks.

Table 1 — Policy Approaches to Enhancing Supply Chain Resilience

Source: Author’s construction.

Applying the supply chain resilience lens to energy security policy can lend important insights into pathways that can transcend politics. Energy security is best accomplished through long-term investments in infrastructure — such as pipelines and transmission lines, as well as rails, roads, and ports — all of which are critical for energy commodity movement between regions. Along those lines, regional policies that effectively segment markets by erecting barriers to trade should also be discouraged. There must also be sustained investment in innovation to drive down costs and increase competitiveness. Ensuring unimpeded opportunities to trade and innovate allows energy producers to capitalize on resource development opportunities, affords consumers access to low-cost energy, and promotes economic growth and prosperity.23

Energy Insights 2026

Kenneth B. Medlock III

It is also important to note that uncertainty delays — and can even prevent — investment.24 As such, government actions that exacerbate uncertainty can derail supply chain resilience. Hence, policy must recognize the importance of building certainty into regulation, siting, and permitting as preconditions for long-term sustained investment, just as it must recognize the importance of establishing market designs that promote transparency and depth for efficient market operations. Government actions that introduce uncertainty in either dimension can have long-term, structural implications that, in the worst case, lead to reduced growth, damage the tax base, and put the U.S. in a precarious fiscal situation. For evidence of this, one need only look at how political instability and a lack of institutional fortitude in various regions around the world have created risky investment environments that have helped prevent resource wealth from translating into economic growth.25

Conclusion The U.S. is in an advantageous position in the current global energy picture. It enjoys a prolific wealth of oil and gas resources (and still has the world’s largest recoverable coal resource base), enjoys an abundance of land that is suitable to capturing some of the world’s best wind and solar resource opportunities, is on the forefront of many energy technology frontiers, has relatively well-developed energy infrastructure, foundational legal and market institutions, and is an attractive place to invest. But taking full advantage of these strengths requires, to the fullest extent, a deeper engagement with the tenets laid out in Table 1 or, at the very least, not violating them outright. In sum, markets are deepened, and energy security is improved when policy and regulation allow trade to occur unimpeded, production to expand without inefficient encumbrances, and new technologies to proliferate and increase competition for different end-uses. Moreover, such a setting can create a virtuous cycle because deeper markets de-risk investment in new infrastructure, which further increases trade and competition, thus increasing fungibility and mitigating extreme price movements. The gist of it all can be summed up in one word: “optionality.” When barriers to trade, investment, and innovation exist, optionality is reduced, and all market participants — both buyers and sellers — are more vulnerable to the negative consequences of unexpected market disturbances.

Energy Security and Supply Chain Resilience

Notes 1

Kenneth B. Medlock III, “Can Trade Help Achieve Energy Security,” World Economic Forum, March 3, 2016, https://www.weforum.org/stories/2016/03/could-trade-help-achieve-energy-security/. 2 For an introduction, see Douglas R. Bohi and Michael A. Toman, The Economics of Energy Security (Springer Dordrecht, 1996), https://doi.org/10.1007/978-94-009-1808-5. For a review of a large number of studies with varying points of emphasis, see B.W. Ang and W.L. Choong et al., “Energy Security: Definitions, Dimensions and Indexes,” Renewable and Sustainable Energy Reviews 42 (November 2014), https://doi.org/10.1016/j.rser.2014.10.064. 3 U.S. Federal Reserve Bank of St. Louis, “Spot Crude Oil Price: West Texas Intermediate,” ALFRED, accessed August 2025, https://alfred.stlouisfed.org/series?seid=WTISPLC; National Bureau of Economic Research, “US Business Cycle Expansions and Contractions,” last modified March 14, 2023, https://www.nber.org/research/data/us-business-cycle-expansions-and-contractions. 4 Dave Roos, “13 US Economic Recessions Since the Great Depression — And What Caused Them,” History.com, last modified May 28, 2025, https://www.history.com/articles/us-economic-recessions-timeline. 5 There is a large volume of research, for example, on the link between crude oil and natural gas prices. See Peter R. Hartley and Medlock, “The Relationship Between Crude Oil and Natural Gas Prices: The Role of the Exchange Rate,” The Energy Journal 35, no. 2 (2013): 25–44, https://doi.org/10.5547/01956574.35.2.2. 6 James D. Hamilton, “Oil and the Macroeconomy Since World War II,” Journal of Political Economy 91, no. 2 (1983): 228–48, https://doi.org/10.1086/261140. 7 Lutz A. Kilian, “Oil Price Shocks: Causes and Consequences,” Annual Review of Resource Economics 6, no. 1 (2014): 133–54, https://doi.org/10.1146/annurev-resource-083013-114701. 8 Knut Anton Mork et al., “Macroeconomic Responses to Oil Price Increases and Decreases in Seven OECD Countries,” The Energy Journal 15, no. 4 (1994): 19–35, https://doi.org/10.5547/issn0195-6574-ej-vol15-no4-2. For an illustration of oil price volatility on the macroeconomy, see J. Peter Ferderer, “Oil Price Volatility and the Macroeconomy,” Journal of Macroeconomics 18, no. 1 (1996): 1–26, https://doi.org/10.1016/s01640704(96)80001-2. Hooker and Hamilton had a journal-style debate on the issues, see Mark A. Hooker, “What Happened to the Oil Price-Macroeconomy Relationship?,” Journal of Monetary Economics 38, no. 2 (1996), 195–213, https://doi.org/10.1016/s0304-3932(96)01281-0; and Hamilton, “This Is What Happened to the Oil Price-Macroeconomy Relationship,” Journal of Monetary Economics 38, no. 2 (1996): 215–20, https://doi.org/10.1016/s0304-3932(96)01282-2. A recent summary is available from Apostolos Serletis and Elaheh Asadi Mehmandosti, “150 Years of the Oil Price-Macroeconomy Relationship,” Macroeconomic Dynamics 23, no. 3 (2017): 1302–11, https://doi.org/10.1017/s1365100517000116. 9 Charles J. Cicchetti and William J. Gillen, “The Mandatory Oil Import Quota Program, A Consideration of Economic Efficiency and Equity,” Natural Resources Journal 13, no. 3 (1973): 399–430, https://digitalrepository.unm.edu/nrj/vol13/iss3/2. 12 Medlock, “Engines of Change: Innovation and Growth,” Rice University’s Baker Institute for Public Policy, August 22, 2024, doi.org/10.25613/KTWT-6639. Much of that report has been effectively recycled to support new energy initiatives today. See National Petroleum Council, Factors Affecting U.S. Oil & Gas Outlook: A Report of the National Petroleum Council, February 1987, npc.org/reports/reports_pdf/1987Factors_Affecting_US_Oil_n_Gas_Outlook.pdf. 13 Energy Policy Act of 2005, H.R. 6, 109th Cong. (2005), https://www1.eere.energy.gov/femp/pdfs/epact_2005.pdf. 14 Energy Independence and Security Act of 2007, H.R. 6, 110th Cong. (2007), https://www.congress.gov/110/plaws/publ140/PLAW-110publ140.pdf.

Energy Insights 2026

Kenneth B. Medlock III

American Recovery and Reinvestment Act of 2009, H.R. 1, 111th Cong. (2009), https://www.congress.gov/111/plaws/publ5/PLAW-111publ5.pdf. 16 For details on the issues being considered at the time, see Medlock, “To Lift or Not to Lift? The U.S. Crude Oil Export Ban: Implications for Price and Energy Security,” Rice University’s Baker Institute for Public Policy, March 24, 2015, https://www.bakerinstitute.org/research/lift-or-not-lift-us-crude-oil-export-ban-implicationsprice-and-energy-security. 17 Infrastructure Investment and Jobs Act, H.R. 3684, 117th Cong. (2021), https://www.congress.gov/117/plaws/publ58/PLAW-117publ58.pdf. 18 CHIPS and Science Act, H.R.4346, 117th Cong. (2021–22), https://www.congress.gov/bill/117thcongress/house-bill/4346. 19 Inflation Reduction Act of 2022, H.R.5376, 117th Cong. (2021–22), https://www.congress.gov/bill/117thcongress/house-bill/5376/text. 20 One Big Beautiful Bill Act, H.R.1, 119th Congress (2025–26), https://www.congress.gov/bill/119thcongress/house-bill/1/text/enr. 21 Any number of articles have investigated factors that contribute to resilience, such as flexibility, redundancy, and collaboration. See, for example, Mansoor Shekarian and Mahour Mellat Parast, “An Integrative Approach to Supply Chain Disruption Risk and Resilience Management: A Literature Review,” International Journal of Logistics Research and Applications 24, no. 5 (2020), https://doi.org/10.1080/13675567.2020.1763935. 22 Medlock, “Modeling the Implications of Expanded US Shale Gas Production,” Energy Strategy Reviews 1, no. 1 (2011), https://doi.org/10.1016/j.esr.2011.12.002. 23 Medlock, “Could Trade Help Achieve Energy Security?” World Economic Forum, March 3, 2016, https://www.weforum.org/stories/2016/03/could-trade-help-achieve-energy-security/. 24 This concept has been well researched and documented. For an in-depth exploration that has withstood the test of time, see Avinash K. Dixit and Robert S. Pindyck, Investment Under Uncertainty (Princeton University Press, 1994), https://press.princeton.edu/books/hardcover/9780691034102/investment-under-uncertainty. 25 For a summary of a Center for Energy Studies research project on this topic, see Medlock and Keily Miller, “The Role of Foreign-Direct Investment in Resource Rich Regions: Research Protocol and Executive Summary,” Rice University’s Baker Institute for Public Policy, February 24, 2020, https://www.bakerinstitute.org/research/role-foreign-direct-investment-resource-rich-regions-researchprotocol-and-executive-summary.

TRANSPORTATION

Without Supply Chains for Fuels, the World Stops

Edward M. Emmett Fellow in Energy and Transportation Policy | CES Lead, Transportation

Introduction It is generally understood that every product has a supply chain by which raw materials are brought together to manufacture that product and then distribute it to consumers.The term “supply chain” has always conjured up an image of links bound together to make a chain. If any link is weak or missing, the entire chain will fail. However, supply chains are much more complex than that simple image. The reality is that each link in a product’s supply chain has its own supply chain, so there are a multitude of factors that could disrupt a product’s ability to either be manufactured or delivered to consumers. While every supply chain is unique, there is one common component necessary for all. That component is fuel. Fuel is required for transporting raw materials to the manufacturing site and the finished product to the consumers. In many instances, fuel is needed in the manufacturing process, too. It is important, therefore, to recognize that fuel is itself a product with a supply chain and the resilience of fuel supply chains is critical.

Without Supply Chains for Fuels, the World Stops

The Evolution of Fuels for Modes Currently, every freight transport mode is fueled primarily by refined petroleum products including gasoline, diesel, aviation fuel, and bunker fuel. Each of those refined products has its own supply chain. Disruptions such as the blockage of the Strait of Hormuz, which reduced the availability of oil for refineries, impact not only the supply chains for transportation fuels but produce a subsequent ripple effect for all other supply chains that rely upon transportation. The extent of those impacts varies. For example, transportation in the United States has little dependence upon oil that comes through the Strait of Hormuz although its availability can affect the price of fuels everywhere thereby increasing supply chain costs and, subsequently, consumer prices.1 Other parts of the world that rely heavily on oil and refined products that move through the Strait of Hormuz are more harshly impacted.2 Since the maturing of the petroleum age, governments and industry have gone to great lengths to ensure resilient supply chains for petroleum and refined fuels. Production, refining, and transportation facilities have been hardened against potential natural disaster. Alternative routes and transport modes have been developed when necessary. A notable example are the pipelines hurriedly constructed from the oil fields of Texas to the East Coast of the U.S. to avoid the risk of submarine attacks on ships during World War II.3 However, the world of transportation is changing dramatically. Concern over climate change and the environment in general has brought pressure on government officials and transportation providers to find ways to reduce carbon emissions and other pollutants that emanate from the exhausts of ships, trucks, automobiles, trains, and airplanes. As a result, a plethora of new fuels are emerging for every mode of transportation. Electricity is powering more and more automobiles, transit, and urban delivery vehicles, but transportation providers are researching and testing many other alternative fuels. Sustainable fuels sourced from cooking oils, animal fats, and agriculture as well as biofuels, various forms of hydrogen and ammonia, and e-methanol are all being tested as fuels. Ocean carriers are already ordering new ships powered by liquefied natural gas (LNG), bio/e-methanol, bio/e-methane, ammonia, and hydrogen. And some in the maritime industry are taking another look at nuclear power for commercial ships since that is a proven technology in the military. Airlines are already using sustainable aviation fuel as a supplement to basic jet fuel, and some governments have issued mandates for its use in coming years. Energy Insights 2026

Edward M. Emmett

Railroads are testing hydrogen fuel cell locomotives The local delivery trucking industry and transit buses, in addition to electric vehicles, are using compressed natural gas (CNG) in some fleets. Long-haul trucking companies are considering renewable diesel as a drop-in fuel for existing equipment, and truck manufacturers are researching new engines fueled by hydrogen and other alternative fuels.

Fuels of the Future: Questions Abound Sustainable fuels sourced from cooking oils, animal fats and agriculture as well as biofuels, various forms of hydrogen and ammonia, and e-methanol are all being tested as fuels. Ocean carriers are already ordering new ships powered by Liquefied Natural Gas (LNG), bio/e-methanol, bio/e-methane, ammonia and hydrogen. And some in the maritime industry are taking another look at nuclear power for commercial ships since that is a proven technology in the military. Airlines are already using sustainable aviation fuel as a supplement to basic jet fuel and some governments have issued mandates for its use in coming years. Railroads are testing hydrogen fuel cell locomotives The local delivery trucking industry and transit buses, in addition to electric vehicles, are using compressed natural gas (CNG) in some fleets. Long haul trucking companies are considering renewable diesel as a drop-in fuel for existing equipment and truck manufacturers are researching new engines fueled by hydrogen and other alternative fuels. There are many questions to be answered with regard to transportation fuels of the future. How much of each fuel can realistically be produced in quantities sufficient to meet the needs of a segment of the transportation industry? How will each mode of transportation choose the best fuel, and will there be commonality of use within each mode? For those fuels that can serve multiple transportation modes, will there be enough availability for competing modes? What role will governments play in deciding the fuels of the future, and will they avoid the temptation to dictate a monolithic answer for each mode? Will governmental policies be coordinated across nations or even across states? Will the future fuels marketplace be driven by fuel suppliers, transport providers, or equipment manufacturers? Will there be geographic differences in fuel used within the various modes? The answers to these questions will determine the efficacy of future fuels, but as each potential fuel is considered, there needs to be a simultaneous analysis of its supply chain. No matter how perfect a fuel might seem, it is virtually worthless without a secure, resilient supply chain.

Without Supply Chains for Fuels, the World Stops

Well-established supply chains exist for gasoline, diesel, aviation fuel, and bunker fuel. Prices might fluctuate due to world events or natural disasters, but these fuels will continue to be available and, as a result, will continue to be the dominant fuels for automobiles, trucks, airplanes, and ships. As alternative, less polluting fuels are proven cost-effective and functionally appropriate, they will face the challenge of developing resilient supply chains. Whatever method for producing hydrogen emerges as the best for various transportation modes, there will be massive challenges bringing hydrogen to consumers as it will require entirely new infrastructure whether it is in its gaseous form or is a liquid. For long-haul trucks and automobiles, the likelihood of gasoline stations and truck stops retrofitting to handle hydrogen is remote. Ocean going ships are more likely to use ammonia as a hydrogen carrier since it is much easier and less expensive to store and transport than pure hydrogen. Use of ammonia as a hydrogen carrier for land-based transportation would have to overcome serious safety concerns before a dependable supply chain could be put in place. The ideal use of hydrogen with the most secure supply chain would be for ships to produce hydrogen from sea water but that is currently only a dream. Renewable diesel and sustainable aviation fuel have the benefit of being drop in fuels that can be accommodated in existing engines, and the refined product can be moved through standard supply chains. That is why they are already in use in the airline and trucking industries. The supply chain issue facing the use of renewable diesel and sustainable aviation fuel (SAF) is finding adequate feedstock and moving it to refineries that have been modified to produce the new fuels. Biodiesel, which is produced from agriculture crops, is chemically different and can only be used by engines specifically designed for the new fuel. As a result, it is not widely available, but gasoline stations and truck stops could easily add pumps for biodiesel and its supply chain would be no different. The broad array of fuels, in addition to ammonia, being considered by ocean carriers to replace bunker fuel all face the need to develop supply chains that involve ports since commercial ships are routinely refueled while docked either at refueling piers or by fuel barges that come alongside. Since most ships have multiple ports of call, it might not be realistic to expect every port to have every future fuel option. Therefore, major ship owners are ordering more dual fuel ships to be built. According to the World Shipping Council, 78% of the container ships and 94% of vehicle carriers on order are dual fuel with methane or methanol being the alternative fuel paired with conventional bunker fuel.4 These vessels are being ordered and built with an eye toward the fuel transition. They will have the capability to switch from bunker fuel to other fuels as soon as they become commercially viable and available at scale. Energy Insights 2026

Edward M. Emmett

In Closing As the world moves toward new, cleaner fuels for transportation and industry, it will not only need the input of scientists, inventors, enlightened officials and transportation companies. There is a major role to be played by logisticians who must design supply chains for each mode of transportation so all other supply chains can continue to function. This will be critical for the future of economies, which will continue to rely on well-functioning, resilient supply chains connected by different modes of transportation, each reliant on fuels.

Notes 1

Congress.gov. "The Strait of Hormuz: Security Developments and Impacts on Oil, Gas, and Other Commodities." October 8, 2026. https://www.congress.gov/crs-product/R45281. 2 Hormuz Strait Monitor. “Which Countries Depend Most on Strait of Hormuz Oil?” Hormuz Strait Monitor, April 8, 2026. https://hormuzstraitmonitor.com/blog/countries-most-dependent-on-hormuz-oil/. 3 Jerrell Dean Palmer and John G. Johnson, “Big Inch and Little Big Inch,” Handbook of Texas Online, accessed October 8, 2026, https://www.tshaonline.org/handbook/entries/big-inch-and-little-big-inch. 4 Gribble, Jordan. “Dual-Fuel Container Ship and Vehicle Carrier Fleet Passes 1,200 Vessels as Orders and Deliveries Rise.” World Shipping Council, May 14, 2026. https://www.worldshipping.org/news/dual-fuelcontainer-ship-and-vehicle-carrier-fleet-passes-1200-vessels-as-orders-and-deliveries-rise.

GLOBAL OIL

Mid-2026 Global Oil Market Outlook: Iran Conflict To Have a Lasting Impact

Abhi Rajendran Nonresident Fellow

Skip York Nonresident Fellow

Introduction The global oil market in mid-2026 has been reshaped by a severe geopolitical shock centered on Iran and the broader Middle East. What had been an oil market expecting to rebalance a significant over-supply has instead been forced into a period of acute supply disruption, elevated prices, deep inventory draws, and renewed questions about the security of Middle East energy flows. Even after the military phase of the conflict fades, the market effects are likely to persist well beyond this year because inventories will need to be rebuilt, supply systems will need to restart, and buyers will reassess the dependability of barrels moving through the Strait of Hormuz. The central market question is no longer simply how loose oil balances were heading into 2026. It is now whether the global system can absorb a prolonged disruption to one of its most important transit chokepoints without creating a new, structurally higher floor for prices. The answer will depend on the duration of the conflict, the pace of normalization in the Strait of Hormuz, the scale of demand adjustment caused by high prices, and the ability of producers in the Americas and elsewhere to respond. 29

Mid-2026 Global Oil Market Outlook: Iran Conflict To Have a Lasting Impact

What To Watch The oil market is now watching a different set of variables than it was before the conflict. Instead of focusing primarily on Opec-plus supply management and the cadence of demand growth, market participants are now trying to understand the duration of physical disruption, the ability of inventories to bridge the gap, and the degree to which the geopolitical risk premium becomes embedded in prices over a multi-year period. Below are the key themes that are likely to shape the market through the remainder of 2026 and into 2027.

Middle East Tensions: A Supply Disruption With Lasting Implications The Iran conflict has become more than a short-lived geopolitical flare-up. The de facto closure of the Strait of Hormuz for multiple months has created a major shock to the global energy system by constraining the movement of crude oil and other energy products through one of the world's most important trade corridors. What once seemed like a lowprobability tail risk has become the defining driver of the oil market in 2026. The conflict has also evolved beyond the narrow question of military escalation. Even with a ceasefire or reduced hostilities, major uncertainties remain around freedom of navigation through the Strait, insurance and financial risk for shipping, damage to energy infrastructure, and the broader diplomatic path surrounding Iran's nuclear program. These complications suggest that the market may not return quickly to the pre-conflict view that Gulf supplies can be counted on with minimal interruption. More broadly, the episode has raised deeper strategic questions that will not be resolved quickly. Regional security arrangements, the degree of trust among the main actors, the willingness to forego future escalations, and the future rules governing passage through the Strait (and potentially other navigation seaways) are all likely to influence oil trade flows long after the immediate conflict subsides.

Supply, Inventories, and Demand: The Market Is Paying the Cost Now The most direct consequence of the conflict has been a large loss of available oil supply to the market. The impairment of flows through the Strait of Hormuz has already required a major adjustment through inventory drawdowns and, increasingly, weaker consumption. The longer production is shut-in production, the greater the restart risk, meaning the eventual recovery in supply may be slower than market expectations. Energy Insights 2026

Abhi Rajendran and Skip York

Inventories have become the market's first line of defense, but they are not distributed evenly. Some countries and regions entered the crisis with substantial crude and product stocks, while others had far less of a buffer and therefore face greater exposure to shortages, high import costs, or both. The result is a highly uneven adjustment process in which refiners, consumers, and governments are all absorbing the shock in different ways. Demand has adjusted with a lag, but that lag is unlikely to persist indefinitely. Higher prices, localized supply tightness, and reduced refining throughput are already feeding through into weaker demand expectations. Forecast revisions are therefore likely to continue, especially if the disruption persists long enough to force permanent cuts in consumption rather than merely deferring growth.

Price Formation: Physical Tightness Has Overtaken Financial Signals One of the clearest signs of market stress has been the divergence between physical oil prices and futures pricing. Spot markets have reflected the immediacy of disrupted supply, while futures contracts eventually moved sharply higher but have not always matched the full severity of prompt physical tightness. That disconnect underscores how difficult it is for paper markets to fully capture the logistics, insurance, and timing problems associated with a prolonged transit disruption with uncertainty about when or if it will end. Even if headline benchmark prices retreat from peak levels, the market is unlikely to return to the pre-conflict price framework quickly. Before the crisis, a world of moderate demand growth and ample Opec-plus spare capacity pointed to Brent in the $60s as a plausible equilibrium range. After this conflict, a higher normalized range is increasingly possible because the market will be discounting lower effective spare capacity, thinner usable inventories, and a more durable geopolitical risk premium. That does not mean prices must remain in triple digits. Demand weakness (from high prices during the shut down and a knock-on effect from slower global GDP), a gradual restoration of flows, and stronger non-Middle East supply growth could all pull prices back down. But the price floor itself may now be meaningfully higher than what the market assumed just a few months ago.

Mid-2026 Global Oil Market Outlook: Iran Conflict To Have a Lasting Impact

OPEC+ and Middle East Supply: Spare Capacity Matters Differently Now The conflict has also changed how the market should think about Opec-plus and spare capacity. On paper, the group may still appear to hold considerable volumes that could eventually return to market. In practice, however, spare capacity is far less valuable if a major regional chokepoint can prevent those barrels from moving freely to customers. This distinction matters for both producers and buyers. Countries such as Saudi Arabia and the UAE retain some bypass optionality through alternative export routes, while others remain far more dependent on the Strait of Hormuz. As a result, restart timelines will differ significantly across producers, and the market may assign a lower confidence value to some portion of stated spare capacity after the conflict ends. The broader political architecture of Opec-plus also bears watching. If members pursue divergent strategies in response to the disruption, or if capacity additions proceed on different timelines, the group's future ability to manage balances may be more fragile than before. UAE’s decision to drop out of OPEC and its pre-war plans for ramping up production beyond the previous levels set by OPEC will also be something to watch.

Demand Outlook: Transient Shock or Structural Shift? For now, the most likely base case is that a meaningful portion of demand destruction proves temporary rather than permanent. If the conflict is resolved and supply channels normalize over the coming quarters, some lost consumption should return as prices ease and product availability improves. Under that scenario, 2026 demand levels would be deferred rather than erased. Still, several parts of the barrel are more exposed than others. Jet fuel, LPG, and diesel are likely to reflect the stress most visibly, particularly in markets where end-users are highly price sensitive or supply chains are less resilient. The path of recovery in those segments may therefore be uneven even if aggregate oil demand eventually stabilizes. A more important question is whether this episode alters expectations through 2030. If governments, consumers, and industry begin to price in greater volatility and insecurity around Middle East supply, the market could see knock-on effects for fuel switching (more rapid growth in EVs), efficiency, strategic stockholding, and broader energy investment patterns.

Energy Insights 2026

Abhi Rajendran and Skip York

Supply Elsewhere: The Americas Move Back Into Focus The longer the disruption lasts, the more attention will turn to supply growth outside the Middle East. The United States remains the most obvious short-cycle source of potential responsiveness, but shale producers are unlikely to accelerate aggressively without confidence that higher prices will be durable and that investor expectations will support faster growth. Even in a stronger price environment, the response is likely to be measured rather than explosive. Elsewhere in the Americas, Brazil and Guyana continue to offer visible medium-term growth potential, while Venezuela remains a more uncertain but potentially meaningful upside case if political and commercial conditions allow investment to return. Canada may also provide some incremental flexibility, although takeaway capacity and logistics remain important constraints. If buyers come to believe that the Middle East can no longer deliver the same degree of reliable supply as before, capital allocation could increasingly favor these non-OPEC producers. That shift will not happen overnight, but the current conflict may accelerate it.

Conclusion: A Market Reset, Not Just a Temporary Disruption The 2026 Iran conflict looks increasingly like a market reset rather than a temporary interruption. The combination of disrupted Hormuz flows, large inventory draws, weaker near-term demand, and renewed doubts about the dependability of Middle East supplies has changed the way the market will think about price risk and supply security. Even after the conflict ends, the oil market is unlikely to snap back to its earlier assumptions. A higher normalized oil price range, stronger emphasis on strategic inventories, and greater focus on supply optionality outside the Middle East are all plausible outcomes. The key issue for the remainder of 2026 is therefore not simply how quickly the market rebalances, but what kind of oil market emerges once it does.

GLOBAL OIL

The Year of the ‘Shock’ What Comes Next? Looking Back To Look Ahead

Kenneth B. Medlock III CES Senior Director | James A. Baker, III and Susan G. Baker Fellow in Energy and Resource Economics This article originally appeared in NAPE Magazine, Vol. 7, No.4, Summer 2026. It is reprinted with permission.

Introduction On Feb. 28, the U.S. and Israel launched a joint military operation against Iran. The subsequent kinetic risk to vessels transiting the Strait of Hormuz drove the maritime insurance industry to announce it would not cover war-related risks, which effectively closed the Strait to traffic. Iran’s ability to demonstrate a credible threat to traffic through the Strait was sufficient to dramatically reduce ship movement.1 After accounting for alternative routing that has been exercised by Saudi Arabia, UAE and Iraq, this disrupted roughly 10 million barrels per day of global crude oil and petroleum product supply and about 80 million tons per annum of LNG supply, as well as large fractions of global aluminum, helium and fertilizer product supplies, exposing massive vulnerability to multiple supply chains. Each is important in its own right, but the focus of this piece will be on oil, with some lessons that translate across different commodity markets. Expanding the time frame, we see three major global supply chain disruptions since 2020: COVID-induced closures of economies around the world followed by discontinuous and inconsistent reopenings in 2020-21. The Russian invasion of Ukraine in 2022. The closure of the Strait of Hormuz in 2026. 35

The Year of the ‘Shock’

Although each was different, they all carried significant implications for energy, food and other raw materials, highlighting how intensely interconnected supply chains are. Indeed, the events since 2020 have demonstrated the value that optionality brings to markets and more generally to energy security equations.2

A Focus on Oil Since 1973, the world has experienced multiple shocks to the energy landscape. Here, we will focus on three significant episodes: the Arab oil embargo, the collapse of the Soviet Union and the oil price escalation before and after the global financial crisis. These three episodes — indicated in Figure 1 along with oil price — provide some interesting evidence of how markets respond to major shifts. In December 1973, the Arab oil embargo resulted in a significant price escalation, on a scale that is multiples of anything witnessed since. Moreover, the price shock did not abate. Rather, it was a structural shift that drove widespread inflation and economic malaise. In the decade that followed, the world also had to contend with the Iranian Revolution and the IranIraq War, but the supply deficit that ensued was entirely offset by new production from countries outside the OPEC cartel — most notably Mexico, the UK, Norway and Russia (see Figure 2). In fact, by 1983, global oil production was about 2 million barrels per day higher than before the embargo, even though OPEC was collectively producing about 11 million b/d less. In other words, investment drove supply diversification into new frontiers. In mid-1990, Iraq invaded Kuwait and was subsequently expelled by an allied coalition led by the U.S. Then, in late-1991, the Soviet Union formally dissolved. The two events resulted in a significant disruption of oil production from Kuwait, which fully recovered by 1992, and Russia, which did not see a reversal of oil production declines until around 2000. Meanwhile, U.S. oil production was in steady decline. Interestingly, these events did not result in a similar structural price impact to what was witnessed in the 1970s. While price did spike for a short period in the wake of the Iraqi invasion of Kuwait, the response by OPEC mitigated it quickly. In addition, the decline of Russian production that continued for the remainder of the decade was more than offset by production growth in multiple locations. Again, investment drove supply diversification. In 2008, the world slipped into a significant recession — the global financial crisis. This was preceded by a continuous rise in the price of oil and other commodities over the previous five years. Energy Insights 2026

Kenneth B. Medlock III

Figure 1 — Oil Price, Real and Nominal (1973-2025, Including 2026 Year-To-Date)

Note: Data sourced for nominal oil price are from the Energy Institute’s Statistical Review of World Energy, 2025, 1973-1983, and the U.S. Energy Information Administration, 1984-2025, and reflect the Arabian Light (at Ras Tanura) and Brent (FOB spot) price, respectively. Conversion to realis done using the CPI for all Urban Consumers from the Bureau of Labor Statistics.

A multitude of aboveground issues related to sanctions, expropriation risks and civil unrest saw oil production decline in some countries, even as oil price climbed to over $147 per barrel, crashed to $30, then settled in at over $100 through 2014. However, production losses of almost 8 million b/d over the next decade were radically offset by production growth from existing exporting countries as well as growth from new frontiers such as shale in the U.S., oil sands in Canada and offshore in Brazil.Yet again, investment drove production gains in new areas. There are other windows of time since1973 that could also be analyzed, but the lesson for oil markets are clear. Regardless of how it is framed — shocks, unexpected shifts or rapid changes to the status quo — the response is universally one of diversification, with longterm impacts that result in a more resilient market. This does not mean the market is immune from future shocks, such as the current issues with the Strait of Hormuz, but each shock is met with responses that mitigate future disruptions of a similar type. 37

The Year of the ‘Shock’

Figure 2 — Change in Oil Production

Note: Data sourced from the Energy Institute’s Statistical Review of World Energy, 2025. Select countries are labeled in each quadrant of Figure 2, and the colors correspond to regions. Red is Asia-Pacific, Purple is Middle East, Gray is CIS, Yellow is Europe, Green is Central and South America, and Blue is North America.

Energy Insights 2026

Kenneth B. Medlock III

Is there a lesson here? Yes. World oil production increased substantially to meet demand over the last 50-plus years. Eventually, geologic and commercial constraints will alter this course, as it does with all depletable resources, but improved recovery technologies and investment in new frontiers still have a say when this occurs. This begs the question of what will happen over the next decade as the response to the trifecta of shocks since 2020 — COVID, the Russian invasion of Ukraine and the closure of the Strait of Hormuz — is fully realized. But global oil and petroleum product demand reached over 104 million barrels per day in 2025, and the legacy infrastructure in place to support that demand — i.e., produce, refine, transport and deliver — is still in place, the fixed costs are sunk, and it will go right back to work as feedstock becomes available.

What Comes Next?3 When thinking about the oil market aftereffects of the current conflict in the Middle East, it is informative to consider what is already happening. Then, placing this in the context of past market evolutions in the wake of disruptions, it is possible to frame what may come next. The closure of the Strait of Hormuz has raised multiple questions about supply chains, choke points, inventory management strategies and the role of government policy, especially in evaluating energy security risks. For market participants, the first step in dealing with this unprecedented constraint was a massive logistics exercise to manage the sudden lack of physical liquidity in the Pacific basin that drove significant regional crude oil price differentials and high levels of price volatility. The second step, which is a continual and evolving exercise, involves finding avenues to flex along existing supply chains to mitigate the existing supply-demand imbalance, especially as inventories are drawn down. This includes, among other things: increasing production at existing locations (to the extent possible); rationing demand in the short term where supplies are inadequate; and finding alternative routes for existing sources of supply to get to market. Markets always find a way to deal with constraints, usually by settling at a much different price. But too high a price carries broader macroeconomic costs, so every option available to the market will be flexed. We have already seen use of alternative routes to avoid the Strait of Hormuz.

The Year of the ‘Shock’

This includes the East-West Pipeline to move Saudi crude oil across the Arabian Peninsula to the Red Sea, the Kirkuk-Ceyhan Pipeline to the Eastern Mediterranean moving Iraqi crude oil through Turkey and the Habshan-Fujairah Pipeline allowing the UAE to move crude out to the Gulf of Oman. In every case, there is express interest in expanding the capability of these routes, with the UAE already announcing an accelerated expansion of pipeline capacity to Fujairah.4 The East-West Pipeline, in particular, provides an excellent case study on the value of redundancy in supply chains. The East-West Pipeline is a 1,200-kilometer system that allows oil and oil products to be shipped across the Arabian Peninsula to the Eastern Province, where it can feed refineries and industrial activity or be loaded for export at the Red Sea Port of Yanbu. Completed in 1981, the system was developed out of an abundance of concern that the newly empowered Iranian regime would exercise control over the Strait of Hormuz. The system had an initial design capacity of 5 million barrels per day that can now be flexed to 7 million barrels per day, which was demonstrated in 2019 after an attack at Abqaiq. A clear lesson was demonstrated then that is playing out now: Insurance in the form of supply chain redundancy can maintain export flows and revenues, even under extreme duress. In fact, imagine a counterfactual where multiple alternative routes to export oil and other products from Saudi Arabia, UAE, Iraq, Kuwait, Bahrain and Qatar already existed. In that world, the closure of the Strait of Hormuz would have a much smaller impact and completely alter the calculus of the current conflict. This point resonates in the region because the ability to trade is vital for the health of those economies, just as the disrupted supply chains are negatively impacting various economic sectors in many other countries around the world.

Diversification Comes in Many Forms While the Middle East will remain vital for market balance, there will be significant interest in diversifying supply chains beyond the Middle East in the interest of resilience. One of the options on the table that has been receiving a lot of attention already, and will certainly expand, involves expanding production in frontier plays in Guyana (offshore), Suriname (offshore), Argentina (Vaca Muerta shale) and Brazil (the Equatorial Margin). Venezuela is an interesting wildcard where rule-of-law and aboveground issues play into an evolving risk dynamic, but the resource potential is attractive. Energy Insights 2026

Kenneth B. Medlock III

While Latin America has historically endured cycles of nationalization and privatization, which carries its own risks, it is less exposed to the type of geopolitical disruption we are witnessing in the Middle East. Moreover, the nature of the investments — highly complex offshore or short-cycle shale — render them less exposed to expropriation.5 Other regions, such as Russia, Africa and North America, will also come into focus for energy resource development. Russia remains one of the world’s largest holders of oil and gas resources, but political dimensions create financial risks that, most likely, will prohibit Western capital from being deployed. However, China, one of the world’s largest consumers, has already demonstrated a willingness to engage with Russia.While this maybe to the chagrin of Western nations, it will help global energy market balance. Africa is also home to tremendous oil and gas resources. Indeed, European nations ramped up engagement with African governments in the wake of the Russian invasion of Ukraine, so those paths are already being pursued. But global interests in expanding supply chain depth in Africa transcend oil and gas, stepping into minerals and metals. Of course, regional conflict remains a barrier for expanded investment, but the costs of the conflicts in Ukraine and Iran, as well as a Western desire to diversify supply chains, are significant counterweights. In North America, investment in oil and gas resource development in the U.S. and Canada, in particular, will be viewed favorably relative to other regions, owing to tremendous unconventional resources, relatively stable legal and regulatory institutions, and access to infrastructure and services that support development. Canada will look to expand export routes to thePacific basin, where it holds an untapped logistical advantage that could connect its vast resources to the largest consuming region on the planet— Asia. U.S. LNG exports have already proved extremely valuable for energy security in Europe and Asia, and petroleum product exports remain promising, especially with a large and complex refining sector that is well suited to handle Canadian and Venezuelan crudes. To be clear, the response in every region will be different. The energy shocks of the 1970s catalyzed multiple responses,6 with regions generally leaning into respective comparative advantages.7 The ramifications of the current energy shock will be no different.

The Year of the ‘Shock’

Some demand-side examples include: China has already demonstrated a preference for electrification, leaning into coal, nuclear and renewables, which has allowed it to redirect LNG imports to Europe and other regions. India will lean into its domestic comparative advantages as well, with coal playing a central role. But the molecules versus electrons path depends on cost, not just of the energy produced, but also the infrastructure required to develop domestic supply chains. Europe will remain an exercise in “political intervention meets market preference” with energy security and energy cost moving to the forefront of political discourse. This will see efforts to expand electrification through domestically produced wind and solar that can facilitate production of e-fuels and green hydrogen. But it will also include greater engagement on the role of Eastern Mediterranean and Central Asian resources, as well as the role of U.S. LNG exports, in an effort to ensure a complete dislocation from Russia. Of course, commercial considerations will bear significant weight on how each path evolves. Capital always chases returns, and the principle of comparative advantage will continue to loom large. Pronouncements of different paths will abound, but pronouncements are not the thing to watch; where capital flows is. Markets have a way of dictating outcomes that highlight returns on investment, regardless of what academics, consultants or commentators may say.

Risks and Insurance The risk exposure revealed by the conflict in the Middle East will drive a substantial wave of new investments, but under a rubric that prioritizes return.The return metric is evolving, and it will incorporate a different risk assessment going forward. Hence, insurance has become more important, and market players will be looking to maximize returns on investment inclusive of insurance premiums going forward. This is generally not new. Firms have long understood the value of things like inventory management as a supply chain resilience mechanism that is de facto insurance at a micro level. This has been elevated at a macro level yet again, much as was the case in the wake of past large market disruptions. As the saying goes — history doesn’t repeat, but it sure does rhyme. Energy Insights 2026

Kenneth B. Medlock III

Notes 1

See Mohammed Omar (Mar 24, 2026), “Insurers Closed the Strait of Hormuz Before Iran’s Navy Could,” House of Saud. Notably, this possibility, and the notion of a credible threat, was discussed at length in D. Brumberg, J. Elass, A.M. Jaffe and K.B. Medlock III (May 2008), “Iran, Energy and Geopolitics,” part of the study The Global Energy Market: Comprehensive Strategies to Meet Geopolitical and Financial Risks, Baker Institute. 2 See K.B. Medlock III (Oct 2025), “Energy Security and Supply Chain Resilience,” Energy Insights 2025, Baker Institute, pp. 11-22. 3 This section draws from K.B. Medlock III (Mar 27, 2026), “How to Straighten Out the Hormuz Bottleneck,” NY Times. 4 See Y. Saba (May 15, 2026), “UAE's new oil pipeline push to double export capacity bypassing Hormuz,” Reuters. 5 See G. Collins, M. Jones, J. Krane, K.B. Medlock III, and F. Monaldi (Dec 2021), “Shale Renders the ‘Obsolescing Bargain’ Obsolete: Political Risk and Foreign Investment in Argentina’s Vaca Muerta,” Resources Policy, Vol 74. 6 See K.B. Medlock III (Oct 2025), “Energy Security and Supply Chain Resilience,” Energy Insights 2025, Baker Institute, pp. 11-22. 7 This point is expounded in K.B. Medlock III (Aug 2024), “Engines of Change: Innovation and Growth,” Energy Insights 2024, Baker Institute, pp. 87-94.

ENERGY AND GEOPOLITICS IN THE MIDDLE EAST

Qatar’s Iran Problem: Maintaining LNG Exports Through Tehran’s Chokepoint Jim Krane Diana Tamari Sabbagh Fellow in Middle East Energy Studies | CES Lead, Energy and Geopolitics in the Middle East

Introduction Iran’s ability to block of the Strait of Hormuz has created a strategic dilemma for Qatar. The peninsular monarchy’s vast liquefied natural gas (LNG) export industry — its primary revenue source — was locked inside the Gulf, with just a handful of cargoes emerging over the four months following the Feb. 28 U.S.-Israel attack on Iran. In normal times, the export pace is two to three cargoes per day. While Qatar’s oil-exporting neighbors plan pipeline and port bypasses to allow future exports to avoid Hormuz, no such alternative is available for Qatar’s fixed LNG infrastructure. The strait remains crucial to Qatari prosperity. As a result, Qatar is incentivized to secure export flows by improving relations with Iran and Oman, the countries bordering — and soon probably administering — the Hormuz trade passage. Qatar might consider a few other hedging options, but none compares with the profitability of unfettered LNG exports through Hormuz.

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Qatar’s Iran Problem: Maintaining LNG Exports Through Tehran’s Chokepoint

A Non-Nuclear Strategic Deterrent Iran has converted proximity to the Strait of Hormuz into a potent strategic deterrent. By blocking maritime trade — including roughly 12% of global oil and 20% of global LNG — Tehran demonstrated that it could imperil the global economy with minimal effort. Unlike a nuclear deterrent, the Hormuz weapon could be readily deployed. And once its effects were demonstrated, Iran was able to reverse the blockage. However, Iran’s impressive leverage is likely to be short-lived. Wars are key drivers of logistics diversification, and Arab Gulf states are already moving to build out new export pathways.1 These include current and future pipelines ferrying crude to less vulnerable ports on the Arabian Sea, Gulf of Oman, Red Sea, and Mediterranean. A complementary push in rail infrastructure, ongoing before the Feb. 28 attack, will improve trade security for commodities, such as sulfur, petrochemicals, and aluminum, alongside critical imports.2 In aggregate, expanded infrastructure will provide redundant pathways for trade that should diminish future disruptions. Unfortunately for Doha, fewer workarounds exist for natural gas. Gas can move to regional markets via pipelines such as the Dolphin Pipeline (3.2 bcf/d capacity, operating at 2 bcf/d3), but Qatar’s primary markets lie far beyond pipeline reach. The state has sunk hundreds of billions of dollars into fixed gas liquefaction infrastructure at Ras Laffan that cannot be relocated. The UAE’s LNG infrastructure, although much smaller, faces the same constraint. In other words, a structural divergence separates the Gulf’s gas-dominant exporters from its oil-dominant exporters. Because of the difficulty in building new LNG terminals, Iran will retain influence over the Gulf gas trade. Qatar will be forced to take a separate path toward de-risking. Doha is incentivized to preserve — and strengthen — its bilateral relationship with Iran, underpinned by their shared management of the world’s largest gas field, known as North Field in Qatar and South Pars in Iran. By contrast, the remaining Gulf monarchies and Iraq face less such pressure, since their exports are dominated by oil rather than LNG.

Energy Insights 2026

Jim Krane

Figure 1 — Qatar and Iran Share the World’s Largest Non-Associated Natural Gas Field

Source: U.S. Energy Information Administration.

Qatar-Iran Relations Prior to the 2026 war, Qatar and Iran maintained a cordial working relationship dating back to the late 1980s. Ties centered around joint development of their shared gas field. Relations had soured previously during the “tanker war” phase of the 1980–88 Iran-Iraq war when two Qatari ships were hit.4 However, a 1990 joint gas development plan and 1991 shipping links revived relations, aligning both states in favor of stability and investment.5

Qatar’s Iran Problem: Maintaining LNG Exports Through Tehran’s Chokepoint

In the early 2000s, Doha convinced Washington of the necessity of consulting Iran, which resulted in frequent high-level visits to Tehran. Relations were pragmatic rather than genuinely warm, and Qatari officials resisted Iranian attempts to broaden the dialogue beyond gas.6 However, Iran played an instrumental role as a conduit for goods during the 2017–20 UAE-Saudi-Bahraini blockade of Qatar.7

2026 War Sets Back Qatar-Iran Relations The 2026 war dealt a severe setback to Qatar-Iran relations, highlighted by the March Iranian attacks on Ras Laffan. With LNG exports already halted by the Hormuz blockade, Iran’s strikes destroyed idled capacity in LNG and in gas-to-liquids processing. “I never in my wildest dreams would have thought that Qatar ... would be in such an attack, especially from a brotherly Muslim country in the month of Ramadan," stated Saad al-Kaabi, CEO of QatarEnergy, following the March 18 destruction of two LNG trains.8

Table 1 — Iranian Strikes/Launches on Qatar Since Feb. 28, 2026

Note: An Iranian strike also hit Al Udeid Airbase on June 23, 2025, destroying a U.S. secure communications and radar installation. Source: Compiled by Gemini Pro query May 29, 2026 from various defense, ministry, and news sources.

Energy Insights 2026

Jim Krane

Postwar Dynamics and Power Vacuum Restoring Doha-Tehran ties will be difficult. The war brought new animosities and extensive, costly repairs. Qatar is also a major non-NATO U.S. ally, where Washington’s influence holds significant sway.10 Further difficulties arise from the security vacuum created by Iran’s asymmetric capabilities, which have fractured regional approaches to Tehran. At one end, the UAE’s pro-Israel alignment meant it bore the highest number of Iranian retaliatory strikes, but also benefited from Israeli security assistance.11 At the opposite end is Qatar: ultra-wealthy but with negligible indigenous defense capacity and far more economically exposed to Hormuz than the UAE, or arguably any other Gulf monarchy. For Qatar, engaging with Washington as a security partner is a matter of national autonomy and perhaps survival. But the deterrence implied by the presence of the forward headquarters of the U.S. Central Command at the Al Udeid Airbase not only failed to provide sufficient protection from Iranian missiles and drones, but created a physical target and a strategic rationale for Iranian attacks.

Strategic Hedging: Re-Friending Iran Qatar’s historical strategy of “balancing” regional threats by maintaining close U.S. military ties is no longer sufficient. It must shift toward a “strategic hedging” strategy that accommodates Iran while retaining hard security ties with Washington. This will be a difficult diplomatic feat. However, the GCC states already hedge their U.S. relationships via deep ties with China. They may be able to boost ties with Iran in ways helpful to navigating an increasingly uncertain international environment.12 For Qatar, strategic hedging involves recognition that Iran is a permanent neighbor, the largest regional power, and one that could be incentivized to help stabilize the regional economic and security structure. The reverse is also true. Without relative prosperity in Iran, security and stability in the entire Gulf region will remain elusive. Further, should Washington or Israel return to warfare with Iran, Qatar’s diplomatic and economic accommodation of Iran could shield it from Iranian retaliation.13

Qatar’s Iran Problem: Maintaining LNG Exports Through Tehran’s Chokepoint

Signs of Qatari-Iranian rapprochement emerged during May 2026. As Table 1 shows, Iranian attacks on Qatar slowed significantly after March. Aside from an April 1 strike on a tanker, launches against Qatar dried up, while strikes against other GCC states frequently exceeded 100 per day.14 Further, seven LNG tankers left the Gulf between Feb. 28 and June 1, including at least three carrying Qatari gas.15

Hedging to Preserve Cost Advantage and Export Security Qatar’s gas-linked security dilemma is not new. A 1981 request to Washington for air defense missiles was driven by fears that Iran would target North Field developments during the Iran-Iraq war. Security assistance from the U.S. and France helped bring Qatari LNG exports to fruition in 1996 when global commodity prices were at historic lows. The initial delivery price to Japan was just $4.10 per mmbtu ($24/barrel oil equivalent), giving Qatar a permanent structural cost advantage, but one that depends on an open Strait of Hormuz.16 In 2024, the LNG trade was under 10% of the $650 billion oil and gas trade out of Hormuz. Qatari LNG exports accounted for just under $50 billion. The loss of those exports — worth about $4 billion per month — is intolerable for a country whose entire 2026 budget was just $60.5 billion.17 One way Qatar could secure Iranian cooperation is by facilitating Iranian LNG exports. Joint development of the combined gas field would not only create Iranian economic dependence on Qatari liquefaction, but would reduce infrastructure costs and provide economies of scale.18 Rather than building stand-alone liquefaction capacity inside Iran, with the accompanying restrictions on U.S. technology transfer and accompanying sanctions or even war damage, the Islamic Republic could simply finance undersea pipeline tiebacks to Qatar, where Iranian gas could be liquefied and exported for a fee.19 The connection between Iran and Qatar might render Doha’s exports and liquefaction facilities less susceptible to Iranian attack. Gulf producers are also hedging by investing in LNG capacity outside the region. Qatar’s joint venture with ExxonMobil at the Golden Pass LNG terminal in Texas opened in April 2026 with an 18 MTPA capacity, offering a modest hedge.20 UAE firms are also investing in Texas and Louisiana LNG terminals.21 More far-fetched options include piping Qatari gas to the Saudi Red Sea coast or across Saudi Arabia or the UAE to Oman’s port of Sur, which sits outside Hormuz.22

Energy Insights 2026

Jim Krane

Conclusion The Iran war has proven extraordinarily costly for Qatar, with the closure of the Strait of Hormuz exposing a major vulnerability in its LNG sector. While other trade can be rerouted via rail or pipeline bypasses, Qatar’s liquefaction capacity is fixed in place. Over time, Iran’s leverage against the other Gulf Arab states will diminish as bypasses expand, but Qatar will remain permanently exposed. Consequently, Qatar’s national interest lies in strategic hedging: balancing a critical U.S. military presence with an improved diplomatic relationship with Iran. Alternate options, such as investing in LNG outside Qatar or long-distance cross-border pipelines, cannot substitute for Qatar’s indigenous low-cost production and liquefaction. The war demonstrated that U.S. security guarantees were insufficient to protect Qatari infrastructure or preserve its access to the strait. As a result, Doha must overcome its wartime animosity toward Iran to rebuild and expand ties.

Notes 1

Gabriel Collins, Wars and Pipelines: How Armed Conflict Has Driven Oil Logistics Diversification, Working paper (Baker Institute for Public Policy, 2026), https://www.bakerinstitute.org/sites/default/files/202604/20260410-Collins-Wars%20and%20Pipelines-Working%20Paper.pdf; Jim Krane and Justin Alexander, Losing Hormuz: The Costs of War for Gulf Oil Exporters, Working paper (Baker Institute for Public Policy, 2026), https://www.bakerinstitute.org/research/losing-hormuz-costs-war-gulf-oil-exporters. 2 Naji Abi Aad, Available Alternatives to Hormuz for Gulf Oil Exporters, Commentary (Gulf Research Center, 2026), https://www.grc.net/single-commentary/360; Jim Krane, Hormuz as Deterrent: How Iran’s Leverage Could Reshape Gulf Infrastructure, Commentary (Arab Center Washington DC, 2026), https://arabcenterdc.org/resource/hormuz-as-deterrent-how-irans-leverage-could-reshape-gulf-infrastructure/. 3 Dolphin Energy, “Operations.” Website, accessed June 3, 2026; https://www.dolphinenergy.com/enUS/Operations/. 4 David B. Roberts, Qatar: Securing The Global Ambitions of a City-State (Hurst, 2017), 71. 5 Roberts, Qatar: Securing The Global Ambitions of a City-State, 71–72. 6 Mehran Kamrava, Qatar: Small State, Big Politics (Cornell University Press, 2013), 84–87. 7 Kristian Coates Ulrichsen, Qatar and the Gulf Crisis (Hurst, 2020), 113, 147-8. 8 “Iran attack wipes out 17% of Qatar’s LNG capacity for up to five years, QatarEnergy CEO says.” Reuters, March 19, 2026; https://www.cnbc.com/2026/03/19/iran-attack-qatar-lng-capacity.html. 9 Justin Alexander, “GCC news to 29 May: Qatar deficit, Kuwait forecasts.” Khalij Economics Newsletter, May 29, 2026; https://www.linkedin.com/pulse/gcc-news-29-may-qatar-deficit-kuwait-forecasts-justin-alexander05wkc/; Also: Moody’s Ratings, Moody’s Ratings Affirms Qatar’s Aa2 Ratings and Maintains Stable Outlook, Ratings agency report (Moody’s, 2026), https://ratings.moodys.com/ratings-news/465847. 10 US Department of State Bureau of Political-Military Affairs, Major Non-NATO Ally Status: Fact Sheet, Government report (US Department of State, 2025), https://www.state.gov/major-non-nato-ally-status/. 11 Burcu Ozcelik, Iran War Grew UAE–Israel Security Ties: Normalisation’s Peril, Promise, Commentary (Royal United Services Institute, 2026), https://www.rusi.org/explore-our-research/publications/commentary/iranwar-grew-uae-israel-security-ties-normalisations-peril-promise.

Qatar’s Iran Problem: Maintaining LNG Exports Through Tehran’s Chokepoint

Ali Bakir and Nayef Al-Shamari, “The Art of Hedging: Qatar, Saudi Arabia, and the UAE Manoeuvres amid US– China Great Power Competition,” Third World Quarterly 46, no. 7 (2025): 773–94, https://doi.org/10.1080/01436597.2025.2509574. 13 Yacoubian and Todman, How Arab Gulf States View the Emerging Iran Deal. 14 https://www.csis.org/analysis/assessing-air-campaign-after-three-weeks-iran-war-numbers 15 Stephen Stapczynski, “Qatar Quietly Ships LNG via Hormuz to Key Buyers.” Bloomberg, May 24, 2026; https://www.rigzone.com/news/wire/qatar_quietly_ships_lng_via_hormuz_to_key_buyers-25-may-2026183767-article/. 16 Tusiani and Johnson, From Black Gold to Frozen Gas: How Qatar Became an Energy Superpower, 334. 17 Krane, Hormuz as Deterrent: How Iran’s Leverage Could Reshape Gulf Infrastructure. 18 This concept was discussed in unpublished research by the Baker Institute Center for Energy Studies in 2015. Also see: Ahmad Kashfi and Wan Adibah, “Joint Development Agreement Scheme for Management of World’s Largest Shared Oil & Gas Reservoir,” Journal of Scientific Research and Development 2 (January 2015): 70–80, https://doi.org/10.2139/ssrn.2623897. 19 Kenneth Katzman, Iran Sanctions, Government report (Congressional Research Service, 2013), https://apps.dtic.mil/sti/tr/pdf/ADA588686.pdf; US Department of State, Iran Sanctions, Government report (US Department of State, 2026), https://www.state.gov/iran-sanctions/. 20 “QatarEnergy marks first export from largest LNG investment in United States.” The Peninsula (Doha), April 23, 2026; https://thepeninsulaqatar.com/article/23/04/2026/qatarenergy-marks-first-lng-export-from-largestinvestment-in-united-states-golden-pass-lng-project-in-texas. 21 Sam Allcock, “Mubadala Energy Closes First Major US Gas Investment.” Aug. 10, 2025; https://abudhabiweek.ae/mubadala-energy-us-natural-gas-investment/ . 22 Krane, Hormuz as Deterrent: How Iran’s Leverage Could Reshape Gulf Infrastructure.

Energy Insights 2026

ENERGY AND GEOPOLITICS IN THE MIDDLE EAST

The GCC Post-War Strategy for Import and Export Resilience Network Salem Alhajraf Nonresident Fellow

Setting the Scene The closure of the Strait of Hormuz caused unprecedented shock to global energy markets by halting the export of approximately 20 million barrels per day of crude oil and oil products. This volume accounts for about 25% of global seaborne oil trade, including refined products such as diesel, gasoline, and jet fuel. The disruption also affected large volumes of petrochemicals, helium gas, aluminum, and other commodities, as well as 112 billion cubic meters of liquefied natural gas, which represents 20% of seaborne LNG trade in 2025.1 2 Additionally, most GCC countries and Iraq were unable to import goods and commodities by sea. As a result, shipments were diverted to alternative ports such as Khor Fakkan and Fujairah in the UAE, and Sohar in Oman, before being transported by road to their final destinations.3 The relative ease with which the Strait was closed, and its severe negative impact on the global economy, was unexpected even by Iranians given that strategic and logistical studies have examined such scenario for over four decades since the Islamic Revolution in Iran.4 This action by Iran revealed a highly influential strategic leverage that surpassed the effectiveness of investing billions of dollars in manufacturing low tech ballistic missiles and drones, as well as financing regional non-state proxies, which have proven inconclusive in resolving conflicts or imposing Iranian terms on the region.

Energy Insights 2026

Free navigation through the strait is unlikely to return to the status quo before February 28, 2026, even if the parties to the conflict reach an agreement to stop the war. The ease with which the strait was closed, along with the negotiating advantages of controlling it, indicates that Iran will likely continue to exploit this strategic asset in future disputes. Iran may pursue this either through direct control of the strait or by supporting new militias operating outside legal frameworks to advance its interests, as demonstrated by its involvement in Bab al-Mandab through the Houthi militia in Yemen. In the aftermath of recent developments, the Gulf Cooperation Council (GCC) states and Iraq have entered a new geopolitical landscape that is unlikely to revert to pre-war conditions. Oman is an exception, as it remains fully independent of Strait navigation for its export and import activities. The Kingdom of Saudi Arabia and the United Arab Emirates have invested in alternative crude oil pipelines to bypass the Strait, successfully rerouting 70% and 45% of their daily crude oil exports, respectively, through the Red Sea port of Yanbu and the Fujairah port on the Gulf of Oman.5 In addition, Iraq exports less than 10% of its daily crude production from its northern oil fields via Ceyhan in Turkey. The situation for Iraq's southern oil fields, as well as for Kuwait, Qatar, and Bahrain, has become critical due to these countries' reliance on the strait to export hydrocarbons, primarily crude oil, LNG, and refined oil products and petrochemicals. At the same time, they rely on the Strait to import all goods and commodities. Iraq recently announced a plan to triple its crude oil exports via a pipeline to Turkey to 770,000 barrels per day, up from 220,000.6 This measure follows a significant decline in oil exports through the strait, which fell to 10 million barrels in April, compared to 93 million barrels per month prior to the conflict.

Resilience of Export/Import Network The closure of the Strait has affected countries to varying degrees, emphasizing the need for more flexible trade routes and alternative corridors that reduce, or potentially eliminate, reliance on the Strait for exports and imports during periods of conflict. Although resilience is often viewed as a costly strategy, its value becomes priceless when it is needed. For the GCC countries and Iraq, redundant export and import routes are essential to maintaining national economic stability, ensuring the continued flow of primary energy resources to global markets, and sustaining reliable supply chains for local markets. This resilience network rests on three key components: ports, pipelines, and railways.

The GCC Post-War Strategy for Import and Export Resilience Network

Integrating logistics networks with Oman’s 1,165 km and the UAE’s 80 km of coastlines would enable the region to bypass the Strait’s maritime chokepoints. Ports and free trade zones such as Duqm, Salalah, Sohar, and Fujairah provide direct access to the Indian Ocean, serving as strategic alternatives to the Strait. Saudi ports on the Red Sea, including Jeddah, Yanbu, NEOM, and Jazan, also offer important options, though they still rely on the Bab alMandeb and the Suez Canal (see Figure 1).

Figure 1 — Major Oil, Gas and Logistics Ports and Existing and Proposed Railways Network Around the Arabian Peninsula

Source: Gulf Cooperation Council Secretary General, UN trade and Development, Author’s rendering. Note: Estimated routes and distances are indicative for presentation only.

Energy Insights 2026

Salem Alhajraf

Ports and Logistic Hubs The Arabian Peninsula hosts more than 29 logistics and hydrocarbon import and export ports. Sixteen of these are located on the Gulf shoreline, which lies behind the Strait of Hormuz; eight are on the Gulf of Oman, the Arabian Sea, and the Gulf of Aden; five are on the Red Sea; and one in land dry port in Riyadh strategically located in the center of the Arabian Peninsula. Additionally, numerous smaller ports serve fishing vessels, passenger transport, and other functions. These ports constitute critical economic infrastructure for the region, facilitating the export of energy resources and the import of goods and commodities from global markets. Each year, GCC ports imports approximately 38 million TEUs (Twenty-foot Equivalent Units).* Jebel Ali Port in Dubai and King Abdulaziz Islamic Port in Jeddah, the region’s two largest ports, have annual capacities of 15 million and 4 million TEUs, respectively. Other regional ports handle between 0.5 million and 4 million TEUs per year.7 8 9 The closure of the Strait of Hormuz directly affects all ports along the Gulf shoreline. Consequently, the GCC and Iraq have initiated efforts to diversify their access to international markets beyond the Strait. This strategic approach enhances the region's resilience against attempts to use the Strait as leverage in both peace and conflict times. The Saudi Arabia’s only inland dry port, located in Riyadh, serves as a major logistics hub, linking Dammam and Riyadh via the country’s oldest operational railway and processing over 500,000 TEUs annually. The Riyadh dry port plays a vital role by connecting the capital to international shipping lines via Dammam port, which accounts for more than 65% of Riyadh’s imports. In alignment with Vision 2030, Riyadh is projected to become a logistics hub connecting the Gulf to the Red Sea and, potentially, the Arabian Sea via Oman logistic hubs.10 NEOM port, located in northwestern Saudi Arabia, completed its first phase, the T1 terminal, in 2026, offering a capacity of 1.5 million TEU. With the future T2 terminal, capacity is expected to increase by 10 million TEU. The port will play a key role in the region’s integrated logistics plan by linking the Red Sea with the GCC, Iraq, Egypt, and other areas. Currently, these connections rely on road transport, with plans to add railroad links as part of the long-term strategy.11

TEU is a standard measure of cargo capacity based on a 20-foot shipping container, widely used in maritime shipping and logistics.

The GCC Post-War Strategy for Import and Export Resilience Network

The Arabian Sea coastline, including the Gulf of Oman and the Gulf of Aden, offers strategic advantages over the Gulf and the Red Sea because it lacks geopolitically sensitive chokepoints. Ports such as Khor Fakkan and Al-Fujairah in the UAE, Sohar, Mina Al-Fahal, Duqm, and Salalah in Oman, and Al-Mukalla and Aden in Yemen operate independently of the three major straits around the Arabian Peninsula. The Port of Fujairah is the UAE's main port on the Gulf of Oman and serves as a key hub for crude oil and oil refined products exports, with storage capacity of 70 million barrels. Unlike Jebel Ali Port in Dubai, which specializes in container handling, Fujairah Port focuses on oil and energy, managing exports and imports of refined oil products and general cargo.12 13 Oman has 3,165 km of shoreline along the Arabian Sea and has strategically developed its ports to advance the export and import security objectives of most of the GCC countries and Iraq. These ports serve as critical nodes for national, regional, and international trade, enabling connections between eastern and western markets. Major logistics hubs include Salalah for general logistics, the Special Economic Zone at Duqm (SEZD) for energy and general logistics, Al-Fahal Port for crude oil export, Ras Markaz for crude oil export and import with a storage capacity of 25 million barrels (including 5 million barrels allocated to the Duqm Refinery), Sohar for general cargo, and Qalhat for LNG export.14 15 Oman's integrated network of ports and logistics infrastructure has strengthened its strategic position, drawing significant interest from regional policymakers and planners as a viable alternative to the Strait of Hormuz. Ports in Yemen that are currently less developed, including Aden and Al-Mukalla, offer additional potential for long-term access to the open sea if the country achieves sustained economic growth and political stability.

Railway Network Railways linking regional ports and logistics hubs, both within and outside the region, are anticipated to play a pivotal role in strengthening import and export resilience. This strategic infrastructure remains indispensable, irrespective of potential peace agreements between the United States and Iran or the reopening of the Strait. The integrated rail network facilitates the export of refined oil products, petrochemicals, and other regional commodities that cannot be transported to ports by pipelines. The same railways will provide an important substitute route for importing essential goods and materials.

Energy Insights 2026

Salem Alhajraf

One of the most significant regional initiatives is the GCC Railway, which was first announced in 2009 during the 30th Supreme Council meeting in Kuwait.16 The project is anticipated to be completed by 2030, although it faces numerous challenges and delays. By 2045, the railway is projected to transport 8 million passengers and 95 million tons of cargo annually. The project is a strategic initiative that aims to connect the six GCC member states through a unified 2,177 km long railway network, enhancing regional connectivity and forming a core component of the GCC's broader transport infrastructure (see figure 1 above).17 Several operational railways exist in the region, yet they are not sufficient. The Dammam-Riyadh railway, which started operations in 1953, has undergone continuous upgrades. It primarily transports cargo from Dammam Port to Riyadh Dry Port over 556 km and provides a passenger service between the two cities.18 Under Vision 2030, the Saudi Railways became integral part of the economic development strategy connecting Asia, Europe and Africa. North-South railway, reaching Saudi-Jordan border town of Qurayyat, is primarily used to transport minerals such as phosphate and industrial goods to Dammam for export. The North-South line is also supporting connection of Riyadh with Qurayyat for cargo and passengers while Haramain railway used mainly for pilgrims between Jeddah, Mecca and Medina. Several new railway projects have been announced to connect major GCC cities and ports for both freight and passenger transport. The Riyadh-Kuwait high-speed railway, a joint initiative between Kuwait and Saudi Arabia, aims to strengthen regional connectivity and boost tourism and economic growth. The 500 km line is scheduled to begin operations by 2030, with the Kuwait Municipalities Council approving the route within Kuwait in May 2026. 19 On December 2025, a new railway project is announced connecting Qatar with Riyadh through high-speed train over 785 km between Riyadh-Doha.20 The initial plan is to dedicate the train for passenger traveling between the two city’s main airports but it is highly expected to expand the goals for cargo and logistics as a result of the closure of the Strait. On 9 June 2026, following the US-Iran war and the closure of the Strait of Hormuz, Saudi and Turkish authorities signed Memorandums of Understanding to cooperate in the railway and logistics sectors. Their goal is to reestablish the Hijaz railroad, connecting Jeddah with Istanbul, to reduce travel time and lower the cost of transporting goods from Asia to Europe. This route will bypass three geopolitically critical straits: Hormuz, Bab Al-Mandab, and the Suez Canal.21 59

The GCC Post-War Strategy for Import and Export Resilience Network

Despite the announced railway projects, logistic routes will still rely on chokepoint straits. To strengthen regional resilience, two additional lines are needed: one connecting Riyadh to the Indian Ocean through Oman, and another linking Riyadh to Turkey via Kuwait and Baghdad, running parallel to the new Hijaz line, as shown in Figure 1.

Oil and Gas Pipeline Network Many cross-border pipelines transport crude oil and natural gas to refineries, power plants, and export terminals along the Gulf, Arabian Sea, and Red Sea coastlines (Figure 2). Several of these pipelines have been constructed and later closed due to geopolitical tensions.22 Three major pipelines currently operate independently of the Strait, collectively transporting nearly 9 million barrels per day. Among these, the Saudi East-West pipeline has a capacity of 7 million barrels per day and extends from the Abqaiq processing facility to the port of Yanbu on the Red Sea.23 The United Arab Emirates' Abu Dhabi Crude Oil Pipeline (ADCOP), with a capacity of 1.8 million barrels per day (mbd), transports crude oil from the Habshan processing facility to Fujairah. The Abu Dhabi National Oil Company (ADNOC) has announced plans to reduce its reliance on the Strait for crude oil and refined product exports by acceleration the construction of the new pipeline that will double the HabshanFujairah pipeline capacity to 3.6 mbd by 2027. Other pipelines are in development stage to completely eliminate dependence on the Strait for both crude oil and refined product exports.24 In Iraq, small amounts of oil are exported via a pipeline running from Kirkuk in northern Iraq to Turkey’s Mediterranean port of Ceyhan. Plans are in place to increase the pipeline’s capacity from the current 220,000 barrels per day to 770,000 barrels per day.25 Several new pipeline projects were introduced even before the closure of the Strait in February 2026. In September 2025, Iraq and Oman reached a preliminary agreement to construct a pipeline for transporting Iraqi oil from Basra to SEZD in Oman, considering both overland and undersea routes.26 27 Before pipeline construction, Iraq and Oman proposed establishing oil storage facilities with a capacity of 10 million barrels at Duqm port in Oman to store Iraqi oil initially transported by tankers. Following the closure of the Strait in February 2026, this project became strategically critical for the security and economic development of both countries.

Energy Insights 2026

Salem Alhajraf

Figure 2 — Existing and Proposed Oil and Gas Pipelines Bypassing the Strait of Hormuz

Source: Global Security Organization28, Qatar-UAE Dolphen Gas Pipeline Project, Author’s rendering. Note: Estimated routes and distances for proposed lines are indicative for presentation only. Commissioned in 2007, the Dolphin gas pipeline transports 2 billion standard cubic feet (bcf) of Qatari natural gas daily to customers in the United Arab Emirates (UAE) and Oman. It supplies approximately 30% of the UAE’s and 6% of Oman's daily gas requirements. The transported gas is primarily used for power generation and water desalination rather than export.29

The GCC Post-War Strategy for Import and Export Resilience Network

Kuwait Petroleum Corporation (KPC), in partnership with the Omani company OQ (formerly Oman Oil Company), invested in an oil refinery project in Duqm. The refinery has been operational since February 2024 and possesses a refining capacity of 230,000 barrels per day. The feedstock crude is supplied exclusively by Kuwait Oil Company (KOC) and Oman QT Group, transported by tankers to the Ras Markaz oil storage facilities. Upon completion, Ras Markaz will have a total storage capacity of 200 million barrels. Currently, 5.2 million barrels are sent to the Duqm refinery via an 80-kilometer pipeline.30 31 Refined products, including diesel, LPG, petroleum coke, jet fuel, naphtha, and sulfur, are exported to international markets through Duqm Port. The construction of additional oil and gas pipelines is critical for the region to maintain resilience on supplying the world with energy resources. These pipelines would enable exports to bypass the Strait and reach the open sea at Fujairah in the UAE, Mina Al-Fahal and Ras Markaz in Duqm for crude oil, and at Qalhat in Oman for natural gas. Collins proposed a jointly utilized pipeline, estimated at $55 billion, to transport 10 million barrels per day of crude oil from Basra, Kuwait, and Saudi oil fields to the ports of Duqm and Salalah in Oman. However, such a joint arrangement would be extremely challenging to implement due to current strategic policy differences among the countries. Consequently, constructing separate pipelines for each nation is a more feasible approach.32 Figure 2 illustrates that the unused initial segment of the Iraq-Saudi pipeline, constructed in the 1980s and ending in Yanbu via Khurais, could be rehabilitated and extended to Duqm. This would allow southern Iraqi oil exports to access the Arabian Sea. Kuwait should also evaluate building a dedicated pipeline to export crude oil via Ras Markaz and supply its partially owned Duqm refinery. Saudi Aramco could consider operating the Shaybah pipeline in reverse from Abqaiq and extending it to Duqm. Qatari gas pipelines could use this route to reach the Qalhat LNG terminal in Oman, or the Dolphin gas pipeline could be upgraded to export through Fujairah or Qalhat. The total estimated pipeline length for this regional resilience strategy would exceed 5,000 km for Iraqi, Kuwaiti, and Saudi crude oil, and nearly 1,000 km for Qatari gas. These proposed lines, together with the UAE’s north-south pipelines, would help ensure continued energy exports if the Strait is permanently closed.

Energy Insights 2026

Salem Alhajraf

Resilience of Network Is a Combination of All No single resilience strategy can guarantee secure and stable access to international markets for countries situated behind the Strait during conflict or peacetime. However, a comprehensive, diversified, and resilient approach is the most effective way to protect the economies of the GCC and Iraq from the potentially severe consequences of a Strait closure, which could be quickly imposed and used as political leverage. Utilizing a mix of existing logistics networks, oil and gas infrastructure, land pipelines, and railways can significantly reduce the economic impact of such an event. The maritime logistics route through the Gulf will remain vulnerable unless reliable access to the open sea is established through pipelines and railways to Oman’s coast. Developing three key railways is essential for diversifying regional logistics and creating land links between the Indian Ocean, Europe, and Central Asia. A primary railway connecting Riyadh Dry Port to the Arabian Sea would enhance logistics resilience against disruptions in the Strait of Hormuz and Bab al-Mandeb. This railway would extend over 1,300 kilometers from the Salalah, Duqm, and Sohar logistics zones in Oman, crossing the challenging terrain of the Empty Quarter. From Riyadh Dry Port, cargo could be distributed to Kuwait, Qatar, Bahrain, and Iraq, and then transported to Europe via the New Hijaz Railway or to Central Asia through the Riyadh-Kuwait-Baghdad-Turkey railway. An integrated oil and gas pipeline network offers a crucial alternative for the region’s energy exports, reducing reliance on the Strait of Hormuz, which handles about one-fifth of global oil and LNG shipments. These pipelines help maintain global supply during maritime disruptions, particularly during geopolitical tensions and regional conflicts, and play a key role in supporting global energy supply and price stability. The integrated export and import resilient network are expected to generate substantial economic and investment opportunities for the region. It also seeks to mitigate risks posed by geopolitical tensions at maritime chokepoints that affect the export of hydrocarbons and their derivatives, as well as the import of goods and other supplies. Although investors may initially question the economic and financial viability of these projects, their strategic value becomes clear during crises, when resilience is essential for national security.

The GCC Post-War Strategy for Import and Export Resilience Network

Notes 1

IEA 2026. Strait of Hormuz. OIES. 2026. Unpacking the Hormuz Crisis. Oxford Energy FORUM. Issue 149. May 2026. Unpacking the Hormuz Crisis: Implications for energy markets and the energy transition - Issue 149 - Oxford Institute for Energy Studies. 3 The Japan Times. 17 March 2026. Gulf importers race to reroute as Hormuz closure jolts supply chains. 4 Lutz Kilian, Michael Plante and Alexander W. Richter. 20 March 2026. What the closure of the Strait of Hormuz means for the global economy. Dallasfed.org. 5 EIA. 2025. Amid regional conflict, the Strait of Hormuz remains critical oil chokepoint - U.S. Energy Information Administration (EIA). 6 Iraq targets tripling its pipeline oil exports. By Pramod Kumar. June 3, 2026. Iraq targets tripling its pipeline oil exports | AGBI. 7 GCC ports rank among world’s top 70 for efficiency in 2024 | Arab News. 19 January 2025. 8 UNtrade and Development. 15 April 2026. Container port throughput https://unctadstat.unctad.org/datacentre/dataviewer/US.ContPortThroughput. 9 DP WORLD RECORDS HIGHEST CARGO VOLUMES AT JEBEL ALI PORT SINCE 2015. 10 Oman Port of Duqm. The Special Economic Zone at Duqm - Inside SEZAD - Profile 11 Port of NEOM. 2026. Port of NEOM and Partners Enable European Multimodal Land Bridge, Advancing Regional Cargo Connectivity . 12 S&P Global Commodity Insights and Fujairah. S&P Global Commodity Insights and Fujairah 2025 . 13 Fujairah Oil Industry Zone (FOIZ). https://foiz.gov.ae/. 14 SeaNav Marine 2024. Major Ports in Oman. 15 Ras Markaz Crude Oil Terminal. Ottco - Ras Markaz. 16 Gulf Railway Project. His Excellency the GCCSG: The GCC Countries are Proceeding with the Practical Steps of the Gulf Railway Project on the Ground, and there are Advanced Levels of Implementation. GCC Secretariat General. 2025. 17 EU, GCC to sign MoU on railway cooperation | Arab News. 18 Saudi Arabian Railways. SAR| Home. 19 Kuwait gives green light for new high-speed rail line to Riyadh - Arabian Business: Latest News on the Middle East, Real Estate, Finance, and More. 20 High-Speed Railway | Qatar & Saudi Arabia. 21 Türkiye and Saudi Arabia sign MoU to revive historic Hejaz route - Türkiye Today. 22 Kristian Coates Ulrichsen and Jim Krane, March 16, 2026. Maritime Chokepoints and Risks to Global Shipping and Energy Security. Rice University’s Baker Institute for Public Policy. 23 Saudi Arabia Restores Full Capacity Oil Flow Via East-West Pipeline Days After Attack | Pipeline Technology Journal. 24 UAE's new oil pipeline push to double export capacity bypassing Hormuz | Reuters. 25 CNBC June 2026. Iraq and UAE race to establish alternative oil pipelines. 26 Oil Pipeline to Diversify Export Routes. September 2025. Iraq and Oman Consider Joint Oil Pipeline to Diversify Export Routes | Pipeline Technology Journal 27 Oman Observer. Oman-Iraq pact on new 10m-barrel crude storage project - Oman Observer. 28 GlobalSecurity.org. Map-pipelines-2010. Last visited 29 June 2026. 29 Qatar-UAE Dolphen Gas Pipeline Project. Resilience of Network is a Combination of All 2

Energy Insights 2026

ENERGY INNOVATION AND POLICY

Airspace Sovereignty Comes to Energy Infrastructure: The 2026 Counter-UAS Inflection Point

Gabe Arrington* Nonresident Fellow

Introduction The security perimeter around America’s energy infrastructure is no longer defined by the fence line. It extends upward. That is not a metaphor. The low-altitude airspace above refineries, petrochemical complexes, LNG facilities, high-voltage substations, power plants, ports, pipeline nodes, control centers, and water systems is becoming part of the operating environment. For years, owners and operators built security around access control, cameras, guards, cyber segmentation, storm hardening, and recovery. Airspace was mostly a federal aviation matter. That division of labor is now breaking down. Small, unmanned aircraft systems are driving the change. Drones are cheap, mobile, expendable, and increasingly capable. They can see over a fence, test a response plan, map a transformer yard, loiter over a flare stack, stream video of guards and gates, carry payloads, or create enough uncertainty to stop work. They compress the space between reconnaissance and action. They also create an uncomfortable legal question: what exactly can a private operator do when a drone is over a critical site and the clock is moving faster than federal response channels?1

* With contributions from Aaron Jon Pasha.

Energy Insights 2026

This is the core policy gap. Operators are being handed responsibility for the airspace above their assets faster than they are being handed clear authority to act. The United States is now moving toward a more serious counter-UAS regime, but detection, restriction, mitigation, and liability still sit in different legal buckets. If 2026 is handled well, it can become the year the country starts to close that gap. If it is handled poorly, the country will ask private owners to carry public risk while leaving them exposed when they make the wrong call, or when they make no call at all. The late-2024 New Jersey drone episode was the moment this problem became visible to the public. Federal officials ultimately said they had no evidence that the reported sightings posed a national security or public safety threat. The FBI and DHS also said many reports appeared to be lawful aircraft or other benign activity. But the episode still exposed a real vulnerability: public anxiety, fragmented authorities, limited transparency, and a domestic counter-drone architecture that did not produce confidence in real time. White House spokesperson John Kirby said the sightings highlighted “a gap in authority” and repeated calls for Congress to expand the ability to identify and counter drones that threaten airports or other critical infrastructure.2 For energy security, that gap matters more than the sightings themselves. A drone over a refinery does not have to be hostile to impose costs. It may force a facility to determine whether the aircraft is lawful, negligent, criminal, or part of a coordinated action. The operator may have only minutes to decide whether to pause work, call law enforcement, activate emergency procedures, gather evidence, or prepare for escalation. The problem is not just technology. It is command authority.

The Threat Has Moved Faster Than the Legal Framework The strategic asymmetry is obvious. A commercially available drone that costs less than a pickup truck can place a sensor, transmitter, or payload over an asset worth billions. The defended object is fixed. The attacking platform is mobile. The defended system is regulated, insured, staffed, and publicly accountable. The drone operator may be anonymous, offshore, criminal, ideological, careless, or merely curious. Energy assets are attractive because they are high-consequence and difficult to move. A transformer station cannot be relocated because the threat vector changed. A refinery cannot pick up its process units and shift them beyond visual range. A port-adjacent petrochemical complex cannot operate in private airspace. The exposure is structural. 67

Airspace Sovereignty Comes to Energy Infrastructure: The 2026 Counter-UAS Inflection Point

The escalation ladder is simple: surveillance, disruption, payload delivery. Surveillance may involve mapping tank farms, substations, security patrol patterns, emergency exits, control buildings, and camera coverage. Disruption may include delaying work, forcing shutdowns, interfering with emergency response, or creating public alarm during a storm, outage, or high-demand period. Payload delivery is the acute case: explosive, incendiary, chemical, electronic, or cyber-enabled devices placed near the part of the facility where a ground intruder would be stopped. None of this requires assuming an imminent catastrophic strike on U.S. energy infrastructure. The point is more basic: the cost curve now favors the attacker. The bulk power system has already shown its vulnerability to physical attacks on fixed assets. The 2013 Metcalf attack in California and later substation attacks demonstrated that determined actors can impose serious consequences with low-cost methods and knowledge of the system.3 Drones add another access path. They do not replace ground threats; they bypass the assumptions that shaped ground security. The same pattern is visible outside the United States. Drones have become tools of reconnaissance, intimidation, and attack in modern conflict. Their tactical use in Ukraine, the Middle East, and near European critical infrastructure has shown how small systems can generate strategic effects. The lesson for the Gulf Coast, the Permian, major ports, nuclear sites, and the bulk power system is not that every drone is a weapon. The lesson is that the distinction between nuisance and threat can collapse quickly when the object is unknown and the asset is consequential.

Washington Is Finally Building the Architecture Executive Order 14305, Restoring American Airspace Sovereignty, signed June 6, 2025, is the clearest federal statement that the low-altitude drone problem has become a homeland security problem. The order states that criminals, terrorists, and hostile foreign actors have intensified the weaponization of UAS and that critical infrastructure is subject to frequent and often unidentified UAS incursions. It sets a policy of protecting the public, critical infrastructure, mass gatherings, and military and sensitive government installations from careless or unlawful drone use.4 In May 2026, the FAA issued a proposed rule to implement Section 2209 by creating a process for eligible fixed-site facility owners and operators to request unmanned aircraft flight restrictions for safety and security reasons. Energy Insights 2026

Gabe Arrington

The Executive Order also calls for national security and homeland security assessments in coordination with sector risk management agencies. It directs online availability of NOTAMs and temporary flight restrictions in formats usable for drone geofencing. It also directs the Attorney General and DHS to ensure that eligible state, local, tribal, and territorial agencies can use grants for detection, tracking, or identification equipment, consistent with their legal authorities.5 For private energy operators, the most important provision may be Section 7. It directs DHS and FAA, in coordination with sector risk management agencies, to publish guidance to aid private critical infrastructure owners and operators in employing technologies to detect, track, and identify drones and drone signals.6 That is useful, but it also shows the problem. Detection is being pushed toward private operators. Mitigation authority remains much more constrained. The FAA’s temporary restrictions during the New Jersey and New York episode illustrate the difference. In December 2024, the FAA temporarily barred drone flights over dozens of critical infrastructure sites, including electrical switching stations, substations, generating stations, a utility command center, and other utility facilities.7 That helped define prohibited activity. It did not, by itself, give a utility crew or refinery security team the authority to jam, seize, redirect, or destroy an aircraft. That is why Senator Tom Cotton’s Critical Infrastructure Airspace Defense Act is consequential. Cotton’s April 23, 2026, announcement describes the bill as legislation to protect critical infrastructure sites from unauthorized drones by ensuring federally trained individuals have authority and tools to protect sites from unmanned aerial threats in real time. The release specifically lists power plants, nuclear sites, airports, pipelines, and dams as examples of covered critical infrastructure.8 The bill text goes further. It would amend Section 210G of the Homeland Security Act of 2002 to grant private owners and operators of covered critical infrastructure facilities, as well as designated security personnel or contractors, authority to take counter-UAS actions necessary to mitigate a credible threat, after completing training and certification.9 It would require DHS, in coordination with DOE, FAA, DOJ, DOD, and DOT, to establish a national certification program with legal, operational, and technical proficiency standards, use of approved technologies, and coordination protocols with FAA to protect the national airspace system.10

Airspace Sovereignty Comes to Energy Infrastructure: The 2026 Counter-UAS Inflection Point

The bill also recognizes two issues that matter in the real world: money and liability. It would create a counter-UAS grant program for critical infrastructure owners and operators, authorizing $250 million for fiscal years 2027 through 2031.11 It would also deem authorized actions to be federal actions for liability-protection purposes, shielding owners, operators, and authorized personnel from civil or criminal claims except in cases of gross negligence or willful misconduct.12 The proposed critical-infrastructure authority would terminate on September 30, 2031, which is a sunset Congress and industry should watch closely.13 This is the right debate to have. Private operators should not become free agents in the national airspace. But neither can the country pretend federal agents will be standing at every refinery, substation, pipeline junction, or port facility at the moment an unidentified drone appears. The operational burden already sits partly with industry. The legal framework has to catch up.

Detection Is Not Mitigation The worst phrase in the counter-UAS conversation is “just jam it.” At a forward operating base, electronic warfare may be a routine part of force protection. At a refinery, LNG facility, airport-adjacent industrial site, or bulk-power control center, radio-frequency jamming can create risk of its own. It can interfere with communications, GPS, aviation systems, emergency response, industrial telemetry, and nearby public networks. Federal law also prohibits willful or malicious interference with authorized radio communications.14 That distinction is why the policy conversation cannot be reduced to hardware. Detection technologies are real and improving. Radar, radio-frequency sensors, acoustic detection, electro-optical systems, Remote ID receivers, and fused analytics can help determine that an aircraft is present, where it is, how it is moving, and whether it is broadcasting an identity. Academic reviews of C-UAS technologies describe a broad ecosystem of detection and mitigation tools, including acoustic, vision, passive RF, radar, data fusion, physical capture, and jamming.15 But a clean radar track is not the same thing as lawful authority to defeat the aircraft. A security team may know a drone is over a tank farm. It may be known that the drone is not broadcasting. It may know the drone is flying where it should not be. It may still lack authority to take active measures. That is the gap between awareness and control.

Energy Insights 2026

Gabe Arrington

The 2018 counter-UAS authorities gave DOJ and DHS tools to detect and disable threatening drones in certain high-risk contexts, but federal officials have repeatedly asked Congress to extend and expand those powers. During the 2024 debate, DHS and DOJ warned that a lapse would create serious homeland security risk and that broader authority was needed for sensitive facilities, borders, prisons, mass gatherings, airports, and critical infrastructure.16 Reuters reporting on congressional testimony likewise noted that officials sought expanded coverage for power plants, oil refineries, chemical facilities, and other critical infrastructure, and that owners or operators could use federally vetted dronedetection capabilities.17 The private-sector lesson is straightforward: buying a detection system is not the same as building a counter-UAS program. A program requires legal review, site prioritization, airspace mapping, threat thresholds, coordination protocols, evidence retention, incident command, insurance review, and exercises with local, state, and federal partners. It also requires discipline. That is not about militarizing every energy site. It is about defining, in advance, who decides, who acts, and who carries the liability when the facts are incomplete.

Energy Infrastructure Is a Special Case Energy infrastructure should not be filed away as just another line item on the critical infrastructure list. Its risk profile is genuinely its own, and it differs from the rest of that list in at least four ways. The Gulf Coast illustrates one half of that exposure: refineries, petrochemical complexes, ports, LNG terminals, gas processing, pipelines, power generation, high-voltage transmission, and chemical manufacturing sit close enough together that a single drone incident can touch public safety, environmental risk, maritime traffic, emergency management, and market confidence all at once. The other half is the electric grid, which depends on thousands of substations, transformers, control centers, generation assets, and transmission corridors scattered across the country with nothing like the same security perimeter. A drone policy built for a football stadium will not automatically work for either one. Layered on top of that geography is interdependence. A refinery needs power, water, feedstock, ports, roads, communications, and process control systems to run, and a pipeline compressor station that looks remote on a map is often operationally indispensable.

Airspace Sovereignty Comes to Energy Infrastructure: The 2026 Counter-UAS Inflection Point

A substation can look like nothing more than a fenced gravel yard and still function as a load-bearing node in a regional reliability system. A drone incident at one site rarely stays contained there; within hours it becomes someone else's business-continuity problem. None of this happens in isolation from the threats the sector already manages. Cyber intrusion, physical sabotage, extreme weather, geopolitical volatility, and supply chain strain were already competing for security budgets before drones entered the picture. Drone risk does not simply add to that list; it connects the items on it. The same aircraft can serve as a surveillance platform, a cyber collection tool, a propaganda prop, or a distraction timed to another incident already underway. And no one outside the fence line understands these assets the way their own operators do. Utility and refinery personnel know blast zones, transformer lead times, emergency shutdown sequences, hazardous material staging, and the real operational cost of a false alarm in ways a federal detection contractor never will. Airspace, however, is federally governed by design. That mismatch between operational knowledge and legal authority is exactly why a workable framework has to be built with industry, not handed down to it. From an energy security perspective, the issue is not whether every critical site should be empowered to take down drones. That would be reckless. The issue is whether the highestrisk sites can enter a regulated pathway that combines restricted airspace, approved detection, trained personnel, law-enforcement coordination, federal oversight, and defined liability. That is where the Cotton bill is most useful as a policy marker, even if Congress changes the details. It names the problem: the owner of the high-risk asset may be the party best positioned to act, but the authority to act has to be granted, trained, limited, and audited.

What To Watch in 2026 and Beyond There are five questions policymakers and operators should track through the rest of 2026. First, will the FAA’s fixed-site restriction process be usable? After years of delay, FAA’s May 2026 proposed rule has moved Section 2209 into implementation the question now is whether the final process will be fast, clear, and practical enough for operators. A portal or process that is slow, opaque, or too narrow will not help operators plan. A process that is too loose could fragment the national airspace. The standard needs to be rigorous and practical. Energy Insights 2026

Gabe Arrington

Second, will FAA restrictions align with DHS and DOJ mitigation authorities? A no-drone area is helpful, but it does not answer the mitigation question. Operators cannot be left in a posture where the federal government says the airspace is protected, the public assumes the facility can act, and the operator’s lawyers know that active defeat is still legally dangerous. Third, how will liability be allocated? If a mitigation action causes collateral damage, who owns the risk? If no action is taken because authority is unclear, who owns that risk? Cotton’s bill addresses this directly by proposing liability protection for authorized actions, excluding gross negligence and willful misconduct. Whether Congress adopts that exact language or not, some version of liability clarity is necessary. Fourth, who gets trained? The answer should not be “anyone with a sensor and a contract.” It should be federally certified personnel operating approved technologies under defined conditions, with FAA coordination and auditability. The country needs a professionalized counter-UAS cadre for critical infrastructure, not a gray market of improvised electronic warfare. Fifth, will operators build the compliance stack before the rules harden? The best companies will not wait. They will inventory high-risk sites, map nearby airspace, identify law-enforcement contacts, evaluate detection options, review insurance, build escalation matrices, and run tabletop exercises. They will know the difference between nuisance, unknown, suspicious, threatening, and imminent. They will also know who has the authority to make each decision.

Conclusion The United States is entering a period when airspace sovereignty will be operational, not abstract. The country will still need innovation, commercial drones, autonomous systems, and UAS integration. But it also needs a serious domestic architecture for the small fraction of drone activity that threatens public safety, national security, and critical infrastructure. Energy infrastructure is where this architecture will be tested. The stakes are high, the assets are fixed, and the operational consequences of confusion are real. The Gulf Coast, the bulk power system, nuclear facilities, pipelines, ports, and petrochemical complexes cannot depend on improvised authority during a live incident.

Airspace Sovereignty Comes to Energy Infrastructure: The 2026 Counter-UAS Inflection Point

Private operators should not become air-defense units. They should operate inside a disciplined framework that matches responsibility with authority: restricted airspace where justified, lawful detection, trained and certified mitigation where necessary, federal coordination, state and local integration, and liability rules that protect good-faith action without excusing recklessness. The fence line still matters. But it is no longer enough. In 2026, the United States has to decide whether the airspace above critical energy infrastructure is merely observed or actually governed.

Notes 1

Executive Order 14305, “Restoring American Airspace Sovereignty,” 90 Fed. Reg. 24719 (June 11, 2025), sec. 1. 2 Andrea Shalal and Ryan Patrick Jones, “FBI, White House Find No Evidence of Security Threat in New Jersey Drone Sightings,” Reuters, December 13, 2024. 3 Richard J. Campbell, Physical Security of the U.S. Power Grid: High-Voltage Transformer Substations, Congressional Research Service, June 17, 2014; Associated Press, “State Lawmakers Propose Power Grid Protections after Attacks,” February 7, 2023. 4 Executive Order 14305, secs. 1 and 3. 5 Executive Order 14305, secs. 5 and 6. 6 Executive Order 14305, sec. 7(d). 7 David Shepardson, “FAA Banning Drone Flights over New Jersey, New York Sites,” Reuters, December 20, 2024. 8 Tom Cotton, “Cotton Introduces Bill to Protect Critical Infrastructure from Drones,” Office of U.S. Senator Tom Cotton, April 23, 2026. 9 Critical Infrastructure Airspace Defense Act, 119th Cong., 2d sess., discussion draft, sec. 3, lines amending 6 U.S.C. 124n(a)(3), released by Senator Tom Cotton, April 23, 2026. 10 Critical Infrastructure Airspace Defense Act, sec. 3, proposed 6 U.S.C. 124n(d)(3). 11 Critical Infrastructure Airspace Defense Act, sec. 4(c). 12 Critical Infrastructure Airspace Defense Act, sec. 5. 13 Critical Infrastructure Airspace Defense Act, sec. 3, proposed 6 U.S.C. 124n(j)(3). 14 47 U.S.C. § 333; see also Communications Act of 1934, as amended. 15 Jian Wang, Yongxin Liu, and Houbing Song, “Counter-Unmanned Aircraft System(s) (C-UAS): State of the Art, Challenges and Future Trends,” IEEE Access 8 (2020): 181–214; Sharad Shrestha et al., “A Comprehensive Survey of Unmanned Aerial Systems’ Risks and Mitigation Strategies,” arXiv, June 12, 2025. 16 Associated Press, “Federal Officials’ Authority to Track and Disable Drones Set to Expire, Snared in Budget Battle,” December 19, 2024. 17 David Shepardson, “NFL, Justice Department Urge Congress to Take Action on Threat from Drones,” Reuters, December 10, 2024.

Energy Insights 2026

ENERGY INNOVATION AND POLICY

AI, Energy, and an Evolving Cybersecurity Landscape Chris Bronk Nonresident Scholar

Context for Discussion Back in 2012, the Baker Institute partnered with Deloitte to bring the cybersecurity issue on the agenda in the oil and gas industry. What we learned from that research drove my belief that more than any innovation by policy or in technology, the sector needed a vastly expanded workforce of highly trained professionals to provide cybersecurity assurance. This prompted me to join the University of Houston’s faculty and build a leading cybersecurity graduate program which has graduated more than a thousand cyber specialists. With innovation in artificial intelligence, a hard look at contemporary cybersecurity is needed. It is not hyperbole to assert that if energy firms get the collision of AI and cybersecurity wrong, there could be dire consequences. This brief provides some guidance in the state of the art for companies in energy, a field that has changed tremendously since our last major review of its cybersecurity. Following a data destruction attack on its Microsoft Windows infrastructure, my colleague Eneken Tikk and I wrote a case study on the hacking of Saudi Aramco in 2012.1 Published as a Baker Institute working paper and in the international security journal Survival in 2013, “The Cyber Attack on Saudi Aramco” has become a widely cited publication on the use of cyber techniques to produce negative economic consequences in energy. Fifteen years later, the club of nations and non-state actors able to produce cyber effects has grown significantly. Further muddying the waters is the empowerment, official or otherwise, of commercial or criminal entities to engage in cyber activity in a blurring landscape of online interaction, AI and interconnected infrastructure.

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While there is a set of issues that are well-known about cybersecurity and the energy enterprise, firms in the energy sector are increasingly able to construct organizational programs to cope with known problems. Borrowing from a former defense secretary, a set of unknown unknowns regarding the security of critical infrastructure that may be largely operated under AI control.2 Although enormous investment is flowing to AI development, the same may not be said for the cybersecurity of it nor its application to energy systems. Much as before, a high-level assessment of cybersecurity and energy is needed, this time focused on responsible and sovereign AI. Time and effort is needed to intensively study responsible and sovereign AI for energy cybersecurity. Offered here is a visit to the issue of cybersecurity as we saw it, in 2012, as well as the remedies that were instituted in the wake of our conference and publications. Beyond that we offer an appraisal of AI and its role in heightening cyber vulnerability as well as the capacity to manage that vulnerability. AI is on many lips right now and for good reason, but it is not a panacea in protecting systems, at least yet, nor will it make the sky fall for energy companies looking to protect their operational and information technologies.

Energy Cybersecurity Issues As with much in the energy industries, outcomes are produced by a combination of workforce and technology guided by strategy, policy and acceptance of risk. While other sectors of the economy may be primarily concerned with the cybersecurity of business computing systems designed to process data, energy firms increasingly adopt computing solutions that drive the operation of heavy industrial plants such as refineries, pipelines and other physical infrastructure. There are several well-known concerns in energy cybersecurity that apply to oil and gas. First and foremost is the issue of compromise for Operational Technologies (OT) and Industrial Control Systems (ICS). Remote operation of up-, mid- and downstream systems by computer has been a major thrust for oil and gas firms for more than two decades. A particularly serious scenario is compromised safety systems. The TRITON/TRISIS malware discovered at a Saudi petrochemical facility demonstrated that attackers could deliberately target industrial safety controllers. We have spent the last decade learning how business and operational systems are interlinked. For example, the May 2021 Colonial Pipeline ransomware attack disrupted the supply of refined fuels to much of the northeastern United States.3 77

AI, Energy, and an Evolving Cybersecurity Landscape

Colonial—a joint venture facility of firms in oil, gas and finance—illustrated how systems for moving products are intertwined with the business systems employed to monitor service and enable financial transactions. The cyberattack on its systems drove new regulation and government oversight into the US pipeline sector.4 Cybersecurity of industrial control systems has shown signs of steady improvement, however. Other areas of critical infrastructure continue to be targeted as well. The August 2026 discovery of compromised water distribution systems in Minnesota, likely by actors tied to Iran, provides yet another example of how infrastructure remains easy to target. Cyberattacks on infrastructure are somewhat exotic, but cyber-based intelligence collection is not. By compromising vendors, such as computer networking management software developer SolarWinds, cyber intelligence operators can provide targeting data for kinetic attack.5 Physical attacks are increasingly guided by open source and cyber intelligence. There is much to be learned about this convergence from the Russo-Ukraine War.6 How has Ukraine successfully targeted energy and military production targets for precision attack? Compromise of Russian computer networks remains a known condition, as it has from early in the war. Those networks doubtlessly are a vehicle for machine-enabled data collection for intelligence purposes. Smartphones are undoubtedly an important part of this intelligence mix as well, chiefly for the location data they generate. Companies and organizations that lauded their cost consciousness with loose, bring your own device data policies are especially vulnerable to pilferage of what could be potential targeting data. The good news for cybersecurity is that much of what is considered the technical side of the area has advanced a great deal. Writing and implementing strong policies has begotten technical solutions for many, but not all, of the well-known cybersecurity vulnerabilities. The bad news is that computing is undergoing a massively significant change due to AI. Because of AI, the topography of cybersecurity is changing.

What Hath Smart Machines Wrought? When OpenAI released the GPT-3.5 Large Language Model in November 2022, the iterative refresh brought with it an enhanced capability for computers to answer myriad questions.7 While large language models (LLMs) are generally known to be capable of answering textbased questions with answers comprised of text, their capacity to generate computer source code is also significant. The practice of combining human hacking with machinegenerated activity is indeed a significant cyber threat. Energy Insights 2026

Chris Bronk

LLMs can lower the technical barriers associated with cyberattacks by generating or adapting computer code from natural-language instructions. An attacker may use an LLM to help write scripts for reconnaissance, vulnerability exploitation, credential theft, malware development, or automating portions of an intrusion campaign. LLMs can also translate code between programming languages, troubleshoot errors, modify tools, and explain unfamiliar software. This potentially allows less experienced actors to perform tasks that previously required greater technical expertise. From a cybersecurity perspective, the principal concern is not that LLMs create entirely new forms of attack, but that they can accelerate development, reduce required expertise, and increase the scale and adaptability of existing offensive techniques. Over the past two years, cybersecurity researchers have documented a growing number of cyberattacks in which artificial intelligence played an operational role rather than merely providing general technical advice. In September 2025, Anthropic detected what it described as the first reported large-scale, AI-orchestrated cyberespionage campaign, attributed with high confidence to a Chinese state-sponsored group. The attackers manipulated Claude Code to conduct reconnaissance, identify and exploit vulnerabilities, harvest credentials, move laterally through victim networks, analyze stolen information, and assist with data exfiltration. Anthropic estimated that AI performed as much as 90 percent of the campaign's operations. The company confirmed that intrusions against several of roughly 30 targeted organizations were successful. Google’s Threat Intelligence Group reported in November 2025 that state-sponsored and criminal actors were using generative AI throughout cyberattacks and identified malware that incorporated AI during execution to dynamically modify its behavior—a significant development beyond simply using LLMs to write malicious code. By 2026, Anthropic identified 832 accounts on its platform involved in malicious cyber activity between March 2025 and March 2026, encompassing techniques across all 14 categories of MITRE’s ATT&CK framework.8 In AI-assisted cyberattacks, human operators hold overall control of the process while using large language models to accelerate discrete tasks such as reconnaissance, phishing development, malware coding, vulnerability research, or translation. Google Threat Intelligence documented this pattern extensively among state-sponsored and criminal actors in early 2025. AI-enabled attacks go further by embedding artificial intelligence directly into malicious tools or operational workflows. Google reported observing active deployment of malware capable of using AI to modify aspects of its behavior during execution, automating a greater number of attack tasks.

AI, Energy, and an Evolving Cybersecurity Landscape

Such was the case in September 2025, when Anthropic identified a Chinese state-sponsored espionage campaign targeting approximately 30 organizations in which Claude Code conducted reconnaissance, vulnerability discovery, exploitation, credential harvesting, lateral movement, data analysis, and exfiltration; Anthropic estimated that the AI independently performed roughly 80–90 percent of tactical operations. By May 2026, Google also reported identifying a threat actor using a zero-day exploit that it assessed was likely developed with AI. Hacking operations are no doubt being enabled by a variety of AI platforms. There’s another problem in the autonomy of AI for cyber applications. Anthropic’s Claude, in three different cybersecurity “capture the flag” evaluations for unnamed companies, escaped an offline environment to compromise systems connected to the Internet. Although no significant damage was inflicted upon any of the outside entities, the failure to contain a Claude “jailbreak” represents a real risk that autonomous computing agents may be up to undesirable action to achieve a desired result. Nonetheless, use of AI for cyber defense is already accruing.

Defensive Benefits? AI can strengthen organizational cybersecurity by helping defenders process more information, detect threats earlier, and respond faster than purely human-centered security operations allow. Machine-learning systems can analyze network traffic, endpoint activity, authentication logs, email, and cloud activity to identify anomalies that may indicate malware, credential compromise, insider threats, or lateral movement. Generative AI can help security analysts correlate alerts, summarize incidents, generate investigative queries, and prioritize the events most likely to represent genuine risk. Microsoft, for example, describes generative AI as increasingly useful for alert triage, incident summarization, threat hunting, and automated containment and remediation workflows. AI can also support a more proactive approach by continuously evaluating an organization's security posture, identifying vulnerabilities and configuration weaknesses, analyzing threat intelligence, and assisting with cybersecurity planning and reporting. NIST's emerging Cyber AI Profile accordingly treats AI-enabled cyber defense as one of three major areas organizations must address and has begun developing guidance for using AI to analyze and monitor implementation of the Cybersecurity Framework. The most effective development model, however, is likely to keep humans responsible for consequential decisions while allowing AI to perform high-volume analysis and routine response at machine speed.

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Chris Bronk

As adversaries themselves increasingly employ AI, organizational cybersecurity will therefore depend not simply on adding AI tools, but on developing integrated, continuouslearning defensive systems that combine automation, human judgment, strong governance, and secure AI architectures. AI can be especially valuable in protecting critical energy infrastructure because AI and machine-learning systems can analyze data from both information technology (IT) networks and operational technology (OT) networks and networked industrial control systems (ICS), establishing patterns of normal behavior and rapidly identifying anomalies that may indicate malware, unauthorized access, manipulation of control systems, or equipment behaving in unexpected ways. The U.S. Department of Energy’s AI-FORTS program includes AI-enabled threat detection, threat hunting, OT/ICS visibility, anomaly detection, incident-response decision support, automated security assessments, and the ability to continue operating through a cyber compromise as important applications for energy security. In the OT/ICS environment AI can also combine cyber information with physical data, such as changes in voltage, frequency, pressure, temperature, or generator performance, to help distinguish a genuine cyberattack from an equipment failure and potentially enable operators to isolate affected components before an intrusion produces cascading physical consequences. DOE has therefore begun developing specialized environments such as the Mjölnir AI testbed, which allow utilities and researchers to evaluate AI and agentic systems safely in realistic environments before deploying them in critical infrastructure. The application of AI may make the technical work of cybersecurity, from patching systems to closing the loop on known vulnerabilities, easier. That said, AI systems will automate cyberattacks in a manner that makes it difficult to predict the potential outcomes.

Concluding Thoughts The topography of the global energy industry has changed tremendously in the past decade and a half. Energy transitions are coupled to an ever-increasing demand for energy. Much that comprises those transitions is controlled or monitored by computer. That computer control may have extraordinary value for society. For instance, Waymo’s self-driving ride service is purportedly many times safer than human driven vehicles such as those operated by Uber, Lyft or other rideshare firms.

AI, Energy, and an Evolving Cybersecurity Landscape

Computer hacking remains a concern, however. The introduction of increasingly sophisticated forms of AI will not spell the end of cybersecurity concerns, at least for now, but it will change them. While AI has changed the landscape for jobs in computing, leading to a significant decline in hiring for coders of software, cybersecurity remains largely untouched, for now. Because of the complexity of the cyber threat, the systems involved and the integration of computing into energy creation and management, it is unlikely that machines will come to dominate the space in the immediate future. The challenge for organizations is to combine human talent with computerized tools to secure a set of infrastructure upon which modernity depends.

Notes 1

Bronk, Christopher, and Eneken Tikk-Ringas. "The cyber attack on Saudi Aramco." Survival 55, no. 2 (2013): 81-96. 2 Rumsfeld, Donald, and Donald Rumsfeld. Known and unknown: a memoir. Vol. 314. New York: Sentinel, 2011. 3 Sanders, Peyton, Chris Bronk, and Morgan D. Bazilian. "Critical energy infrastructure and the evolution of cybersecurity." The Electricity Journal 35, no. 10 (2022): 107224. 4 Kilovaty, Ido. "Cybersecuring the pipeline." Hous. L. Rev. 60 (2022): 605. 5 Bronk, Chris, and Wm Arthur Conklin. "Who’s in charge and how does it work? US cybersecurity of critical infrastructure." Journal of Cyber Policy 7, no. 2 (2022): 155-174. 6 Bronk, Chris, Gabriel Collins, and Dan S. Wallach. "The Ukrainian information and cyber war." The Cyber Defense Review 8, no. 3 (2023): 33-50. 7 Ray, Partha Pratim. "ChatGPT: A comprehensive review on background, applications, key challenges, bias, ethics, limitations and future scope." Internet of things and cyber-physical systems 3 (2023): 121-154. 8 Al-Sada, Bader, Alireza Sadighian, and Gabriele Oligeri. "MITRE ATT&CK: State of the art and way forward." ACM Computing Surveys 57, no. 1 (2024): 1-37.

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ENERGY, MINERALS, AND MATERIALS

The Hidden Constraints on Critical Minerals Finance A Roadmap to U.S. Critical Minerals Funding, 2018 to 2026: Who Funds Which Mineral, From Which Appropriation, and in Which Structure

Ashley Zumwalt-Forbes Nonresident Fellow

Where the Critical Minerals List Came From Being named a critical mineral is often viewed as the “finish line” in industry, after which government capital, expedited permitting, and offtake support start pouring in. In this paper, I explain what the list actually gets you, how funding has evolved over Administrations, and which offices and funding authorities may be relevant to specific critical minerals projects. Executive Order 13817, signed in December 2017 under the first Trump Administration, directed the Department of the Interior to publish a critical minerals list. The U.S. Geological Survey (USGS) did so in 2018, naming 35 minerals.1 The Energy Act of 2020 subsequently wrote the definition into statute and required USGS to refresh the list at least every three years. The list then grew to 50 minerals in 2022 and again to 60 in 2025. Not to be outdone, the Department of Energy keeps a separate critical materials list of 18 materials, most but not all of which also appear on the USGS list (electrical steel and silicon carbide, for instance, do not), built specifically for energy technologies. The tax code, in Section 45X of the Inflation Reduction Act, carries its own statutory list of 50 minerals (51 if you include metallurgical coal, added by the One Big Beautiful Bill Act, OBBBA, of 2025). The Department of Energy funded rare earth and critical materials research through its Critical Materials Institute at Ames as far back as 2013, but those early outlays are dwarfed by today’s investments, so this roadmap tracks the money and policy from 2018 onward. None of this is to critique any Administration, but rather to orient the reader to the evolving nature of critical minerals funding.

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How the Government Allocates Funding Among 60 Critical Minerals The USGS critical minerals list is not tied to a magical funding mechanism. Critical minerals funding has evolved through Administrations. Table 1 shows the evolution of both the USGS list and the minerals receiving funding under each Administration. Table 2 shows funding deployed by agency or department under each Administration. This document captures deals disclosed publicly as of 27 June 2026. On the numbers, treat the totals and charts as indicative and directional. The point is to show evolution over time, not to publish an audited ledger.

Table 1 — Minerals and Capabilities Funded, by Administration

Table 2 — Capital Deployed by Agency/Department, by Administration (Announced $, Committed + Indicative)

Note: EXIM and OSC totals are heavily indicative (letters of interest, the $10B Project Vault reserve, conditional loans). Treasury 48C is shown at the ~$2.3B public critical-materials category total (see Notes for the breakdown and disclosure rule).

The Hidden Constraints on Critical Minerals Finance

The Buckets of Capital Federal support comes from roughly a dozen buckets of capital, each with its own appropriation, structure, and eligibility rule. Approximate sizes and remaining balances are shown where public; many are credit-subsidy ceilings rather than cash, and several FY2026 figures are unsettled, so estimates are flagged.

Table 3 — Funding Mechanisms, Where They Sit, Typical Size, and Who Qualifies

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The League Tables The lead agencies, the funding structures, and the favored minerals all evolved across the three covered Administrations. Under Trump 1, the target was rare-earth separation and magnet-making, in the form of grants. Under Biden, the focus was the energy transition, semiconductors, and batteries, in the form of grants, tax credits, and loans. Under Trump 2, the focus has been materials under Chinese export restriction, in the form of dilutive equity stakes, price floors, loans, grants, and stockpile purchases (Figure 1). Figure 2 maps which agency has funded which mineral under which Administration.

Figure 1 — Committed and Indicative Dollars, by Administration

Note: 48C is excluded from the figure breakdown because not all awards are public; including it would understate the category.

Figure 2 — Which Agency Funded Which Mineral, and What Is Still Active Under Trump 2

The Hidden Constraints on Critical Minerals Finance

Where to Take a Project Today Table 4 turns current Trump 2 priorities into a practical routing guide: given where a project sits today, where to look first, and how likely federal money is.

Table 4 — Project Pathways

The Minerals That Have Not Received Direct Support Of the 60 USGS-defined critical minerals, 17 (~28%) have not received a direct federal funding deal. They fall into two groups: the platinum-group metals (platinum, palladium, rhodium, iridium, and ruthenium) and a dozen industrial minerals (arsenic, barite, beryllium, cesium, chromium, fluorspar, hafnium, lead, rhenium, rubidium, silver, and zirconium). Additionally, metallurgical coal sits on the 45X list and phosphate has seen permitting support, but neither commodity has disclosed direct project support. One caveat belongs here: 48C recipients are confidential unless they consent to be named, so it’s possible that some of these minerals could have received 48C tax credit support that is simply not in the public domain. Energy Insights 2026

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Even so, the pattern reinforces the theme of this paper: being on the list does not, by itself, bring funding. A mineral earns capital when an agency has an appropriation, a structure, and a reason to act, not when USGS adds it to a list.

How Priorities Changed From 2018 to today, the record shows priorities rotating through up to about twenty minerals at a time, never the full list, and reaching for different investment structures with different Administrations. For a developer who needs government support, the question of financing is which funding mechanisms are open, which agency owns the material, and what the Administration’s priorities are.

Fix 45X and Improve Bankability Every item in this roadmap is an individually negotiated transaction. The Section 45X production credit is the exception: it is claimed on a tax return rather than awarded deal by deal, so it could reach far more producers, and more of the chokepoints, without an agency structuring each deal. It does not reach the right materials in the right amounts today, because it is tied to a separate statutory list of 50 minerals plus metallurgical coal, and, in 2025, OBBBA put a sunset on it that zeroes the credit by 2034. A forthcoming paper in this series, on rebuilding Section 45X, sets out how to make it permanent, reach the true supplychain chokepoints, set different rates by criticality and emergency need, and aim it at the materials that matter most, so that producers can rely on a predictable credit instead of negotiating each deal one at a time.

The Hidden Constraints on Critical Minerals Finance

Selected Sources Primary references for the framing facts: the critical minerals list and Executive Order 13817 (Federal Register, 2018 and 2025; usgs.gov); the DOE critical materials list of 18 (DOE 2023 Critical Materials Assessment, Federal Register 2023-16611); the Section 45X(c)(6) statutory list and metallurgical-coal addition (26 U.S.C. 45X; One Big Beautiful Bill Act, 2025); the Critical Materials Institute at Ames ($120M, 2013, energy.gov/ameslab); the 48C critical-materials category of ~$2.3B ($0.8B Round 1, DOE; $1.5B Round 2, Treasury press release JY2779; IRS Announcement 2025-22); and the CHIPS GaN gallium awards (Department of Commerce, GlobalFoundries and MACOM, 2024). Public deals are documented in agency and company disclosures, including: MP Materials and the Department of Defense (mpmaterials.com; war.gov); Lithium Americas / Thacker Pass and DOE LPO (energy.gov); Perpetua Resources and EXIM (exim.gov; prnewswire.com); the DOE BIL 40207 battery rounds (energy.gov; netl.doe.gov); DoD DPA Title III awards (businessdefense.gov; war.gov); 48C allocations and the ~$2.3B critical-materials category (Treasury press release JY2779; DOE Round 1 release; IRS Announcement 202522); CHIPS GaN gallium awards (GlobalFoundries and MACOM, Department of Commerce); USGS Earth MRI (usgs.gov); DFC investments including Orion and TechMet (dfc.gov); and the Korea Zinc Clarksville partnership (nist.gov; koreazinc.co.kr). Full deal-level citations are maintained by the author.

Notes 1

Executive Order 13817 (December 20, 2017) created the federal critical minerals framework; USGS published the first list of 35 minerals in 2018. The Energy Act of 2020 codified the definition and the three-year update cycle. Subsequent USGS lists: 50 minerals (2022), 60 minerals (2025). The DOE critical materials list (18 materials) and the Section 45X(c)(6) list of 50 applicable critical minerals plus metallurgical coal are separate lists. 2 Pre-2020 funding included the July 2019 DPA Title III rare-earth determinations and the launch of USGS Earth MRI mapping (~$11M per year from 2019, raised to ~$75M per year by a $320M Bipartisan Infrastructure Law allocation in 2022). The DOE Critical Materials Institute at Ames received $120M in 2013, predating the list, and is context rather than counted. 3 Deal record compiled by the author from public agency and company disclosures as of 27 June 2026, and acknowledged to be incomplete. Committed figures cover grants awarded, loans closed, equity taken, stockpile contracts signed, and named 48C allocations; indicative figures cover letters of interest and conditional commitments. The 45X production credit is claimed on returns and is not itemized by company, so it is not reported here. On 48C specifically: recipient names are confidential unless the taxpayer consents (or at certification under IRC 48C(e)(7)). The full ~$2.3B critical-materials category ($0.8B Round 1 per DOE; $1.5B Round 2 per Treasury JY2779) is included in committed totals, but only the ~$1.0B of publicly named projects is itemized; the ~$1.3B balance is a confidential line, so some minerals may have undisclosed 48C support. 4 Korea Zinc Clarksville is counted at the U.S. piece only. Japan’s $550B and Korea’s $350B trade-deal funds are allied capital not U.S. capital, so are tracked separately and excluded from federal totals. Private and World Bank funds (Appian-IFC) are excluded unless a specific U.S. co-investment exists (only DFC’s $600M Orion share is counted). DFC's TechMet equity ($75M committed, ~$105M reported) is also counted, alongside the $600M Orion share. The foreign co-investors in these U.S.-backed vehicles are likewise disclosed and excluded from U.S. totals: Qatar's QIA invested $180M in TechMet (August 2024) and the UAE's ADQ committed $600M to the Orion consortium; only the DFC shares are counted as U.S. capital.

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Ashley Zumwalt-Forbes

The 45X redesign is developed in a forthcoming paper in the Critical Minerals Capital Series, alongside Technical Disclosure (Paper 1), Byproduct Metals (Paper 2), Keeping Adversarial Capital Out (Paper 3), and Bifurcated Reference Pricing (Paper 4). 6 What this roadmap does not capture: the Section 45X production credit (claimed on returns, not itemized by company) and undisclosed 48C awards (Note 3) are excluded by their confidentiality, as are indirect measures such as the consumer electric-vehicle credits that pull demand (removed in OBBBA), Section 232 tariffs, and royalty or permitting relief. Several Bipartisan Infrastructure Law provisions also sit outside the count: Section 40209 (Advanced Energy Manufacturing and Recycling, $750M, broad advanced-energy with some critical-materials recycling), Section 40208 (battery recycling R&D), Section 40210 (critical-minerals mining and recycling research, ~$100M/yr authorized but not appropriated), and Section 40206 (permitting). EPA's role is recycling grants (SWIFR, REO), not mineral supply, and USGS Earth MRI is national mapping rather than project funding. Other agencies were checked and left out as immaterial direct funders: the SBA (only small SBIR/STTR awards), the State Department (the Minerals Security Partnership is diplomatic coordination, captured via DFC and EXIM), and NASA and the Department of Transportation. Small research grants below ~$5M are recorded at the program level.

ENERGY, MINERALS, AND MATERIALS

From Rocks to Renewables: Will Critical Minerals Constrain the Energy Transition?

Osmel Manzano Nonresident Fellow | Principal Economist, Inter-American Development Bank

Daniela Valdivia Researcher, Instituto de Estudios Peruanos

The Energy Transition as an Extractive Transition Today's energy transition resembles the period around 1950. In the early postwar period, energy demand expanded rapidly, oil became central to industrialization and mobility, and countries faced the challenge of building the institutions required to govern production, trade, and resource rents. The current transition presents a similar scale-up challenge: expanding mineral supply together with the processing capacity, logistics networks, and infrastructure needed to support it. However, the political context is no longer the same. The world has changed in ways that reflect broader democratization and the need for actors to be heard. Extractive projects no longer operate in environments where local communities can be treated as passive recipients of national development strategies. Instead, project outcomes are shaped by a wide set of actors, including communities, indigenous groups, subnational governments, environmental organizations, courts, investors, and international arbitration mechanisms. 93

From Rocks to Renewables: Will Critical Minerals Constrain the Energy Transition?

The Andean region represents a microcosm of this broader transition. Colombia, Ecuador, and Venezuela face declining demand for fossil fuels because of their dependence on oil revenues, while Bolivia and Peru are exposed through natural gas production. At the same time, growing demand for lithium, copper, silver, graphite, cobalt, and other critical minerals creates new opportunities. Bolivia holds some of the world's largest lithium reserves, Peru is a major producer of copper and precious metals, and several countries across the region have significant untapped mineral potential. For Andean countries, the energy transition is also an extractive transition. The energy transition does not eliminate extraction; it reconfigures it. What changes is not only what is extracted, but also where extraction takes place, who benefits from it, and under what institutional and political conditions it is governed. The result is a complex policy challenge. Countries dependent on hydrocarbons must manage declining external demand and revenue volatility. Countries rich in minerals must expand production while maintaining social and environmental legitimacy. And countries with exposure to both sectors face overlapping transition risks, including stranded fossilfuel assets, rising expectations around mineral development, increased social conflict, regional inequality, and mounting environmental pressures. This raises an important question. If the energy transition depends on a massive expansion of mineral extraction, could critical mineral scarcity become its main bottleneck?

From Resource Scarcity To Institutional Scarcity Every major energy transition has generated concerns about resource scarcity. During the twentieth century, fears centered on oil depletion; today, they increasingly focus on the availability of critical minerals. The concern is understandable. Clean energy technologies are significantly more mineral-intensive than the fossil-fuel systems they are intended to replace. Electrified transport depends on batteries, which require lithium, nickel, cobalt, graphite, and other minerals. Renewable energy systems require expanded transmission networks, transformers, copper wiring, steel, aluminum, and storage technologies. At the same time, the rapid growth of artificial intelligence and data centers is increasing electricity demand and placing additional pressure on energy and mineral supply chains. However, history suggests that physical scarcity alone is unlikely to become the decisive constraint on the energy transition. Morris Adelman’s Genie out of the Bottle1 described this process and challenged the idea that oil is a scarce resource controlled by a few, arguing that the market is more complex. Energy Insights 2026

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Similarly, Daniel Yergin's The Prize2 argues that perceived or temporary scarcity is driven by geopolitics, market cycles innovation, new frontiers, and political control. Energy systems therefore evolve through strategic adaptation rather than geology alone. Figure 1 illustrates this point. Between 1950 and 2019, global oil production increased almost ninefold, rising from approximately 10.9 million barrels per day to 94.9 million barrels per day. Yet the theoretical duration of reserves did not decline accordingly. Instead, reserve life fluctuated and ultimately increased from roughly 19 years in 1950 to about 50 years in 2019. The lesson is not that scarcity is irrelevant, but that it is dynamic. Resource availability changes as exploration expands, technologies improve, prices evolve, and institutional and regulatory conditions adapt. This dynamic perspective is captured by the well-known phrase often associated with Sheikh Ahmed Zaki Yamani: "The Stone Age did not end because the world ran out of stones, and the oil age will not end because the world runs out of oil." Whether or not the attribution is precise, the underlying idea is powerful. Energy transitions are driven not simply by the exhaustion of resources but by technological innovation, economic incentives, political decisions, and changing social preferences.

Figure 1 — Oil Production and Theoretical Duration

Source: U.S. Energy Information Administration (EIA).

From Rocks to Renewables: Will Critical Minerals Constrain the Energy Transition?

The history of oil highlights three mechanisms that repeatedly prevented physical scarcity from becoming a binding constraint. First, exploration continuously expanded the resource base through the discovery of new producing regions, including the Middle East, Siberia, Kazakhstan, and Mexico's Cantarell field. Second, technological progress transformed resources that had previously been considered uneconomic into commercially viable reserves. Examples such as the North Sea, Canada's oil sands, Venezuela's Orinoco Belt, and the shale revolution demonstrate that resource endowments are not fixed categories; they become economically viable as technology advances and market conditions evolve. Third, institutions determined whether those resources could actually be developed. End of civil wars, secure property rights, contractual stability, effective fiscal regimes, functioning capital markets, specialized service firms, and political stability all influenced the pace and scale of resource development. Critical minerals are likely to follow a similar trajectory. New deposits will continue to be discovered, lower-grade ores may become economically viable, recycling technologies will improve, substitution will reduce dependence on some minerals, and innovation will alter the mineral intensity of batteries, electricity networks, and renewable energy technologies. As in the history of oil, geological endowments represent only one component of future supply. Yet the history of oil offers a second lesson. Physical resources alone do not determine whether production expands; political institutions shape how resources are governed and who ultimately controls them. As Adelman and Yergin show, oil became the world's most strategic commodity, with international alliances, conflicts, and market dynamics increasingly shaped by access to petroleum. Much of the twentieth-century oil economy therefore evolved in a geopolitical environment where strategic interests often prevailed over domestic accountability, and where many major producers were governed by nondemocratic regimes, as documented by Levitsky and Way.3 These political conditions also had important economic consequences. Although the global economy today requires substantially less oil to generate the same level of output than it did in the 1960s, its relative cost is much higher. Therefore, petroleum remains a strategically important commodity. Improvements in efficiency have not eliminated its economic or geopolitical significance. However, the political context surrounding today's energy transition is fundamentally different. As Levitsky and Way argue, the expansion of democracy since the 1970s has transformed the institutional environment in which natural resources are developed. Although democratic backsliding has occurred in recent years, democratic institutions have proven remarkably resilient. Energy Insights 2026

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As a result, critical minerals are likely to be developed under political conditions that differ substantially from those that characterized the rise of the global oil economy. In this context, the central question is no longer whether sufficient mineral resources exist beneath the ground, but whether countries possess the institutional capacity to develop them rapidly, responsibly, and legitimately enough to support the clean energy transition. Doing so requires stable investment rules, effective environmental governance, and meaningful participation by affected communities. The principal challenge is therefore shifting from resource scarcity to institutional scarcity. The world may possess sufficient mineral resources below ground, but it may not yet possess enough institutional capacity above ground to develop them at the speed and scale that the transition requires.

Social License and Institutional Legitimacy Among the various dimensions of institutional capacity, social legitimacy has become increasingly important. Latin America and the Caribbean have the highest prevalence of mining-related conflicts globally. According to the OCMAL database, which covers approximately the last two decades, there are ten recorded conflicts in Bolivia, nine in Ecuador, nineteen in Colombia, forty-six in Peru, and two in Venezuela.5 These conflicts are not primarily driven by opposition to development itself, but by perceptions that the distribution of costs and benefits from extraction is unequal. The Social License to Operate (SLO) is understood here as the social approval granted by communities and stakeholders to an extractive project.[2] Unlike legal permits, it depends on trust, legitimacy, and perceptions of fairness in how benefits and burdens are distributed. This distinction is important because projects that are legally approved can still face delays, cost overruns, or suspension due to social resistance. Survey evidence from Bolivia, Colombia, Ecuador, Peru, and Venezuela shows that majorities often recognize positive national impacts from mining and hydrocarbons, as shown in Figure 2.6 Support for extractive industries is therefore not absent. Favorable views are widespread across the region, with hydrocarbons generally receiving stronger support than mining, and Bolivia and Venezuela showing higher levels of support than Colombia.

From Rocks to Renewables: Will Critical Minerals Constrain the Energy Transition?

Figure 2 — Citizen Perception of Extractive Industries

Source: Adapted from Andrian et al. (2023), based on Balza et al. (2021).

However, broad support for extractive industries should not be interpreted as a fully established SLO. Positive perceptions coexist with persistent concerns regarding participation, trust, and the distribution of benefits. Respondents frequently express support for extractive activity in principle while emphasizing a lack of voice in decision-making, concerns about how benefits are distributed, and doubts about whether companies adequately engage with affected communities. Governance capacity matters, but it is not always the primary constraint. Citizens may trust that governments have some capacity to regulate while still distrusting firms and the way benefits are shared. Two dimensions of legitimacy help explain this pattern. Distributive justice refers to how benefits and costs are allocated, whereas procedural justice concerns whether communities are meaningfully consulted and heard. Respondents who perceive firms as failing to listen to communities are more numerous than those who believe firms do listen. This represents a major constraint for critical minerals: projects may be economically viable and strategically important, yet still fail if local communities perceive decision-making processes as unfair or exclusionary.

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Experimental evidence reinforces these findings. Citizens support compensating regions affected by environmental impacts, allocating a larger share of royalties to producing provinces, and favoring mining projects with lower environmental impacts and stronger community engagement.7 These preferences indicate that both meaningful consultation and fair compensation are central components of social acceptance. The distributive dimension is particularly important because fiscal systems are the primary mechanism through which governments seek to convert resource extraction into tangible public benefits. Across the Andean region, governments have developed a broad set of fiscal instruments to capture resource rents and redistribute the benefits of extractive activities across levels of government. These instruments include royalties, corporate income taxes, special mining levies, hydrocarbon taxes, windfall profit taxes, mining canon systems, and other revenue-sharing mechanisms.8 While the specific design varies across countries, they share the common objective of transforming extractive revenues into public resources for national and subnational development. However, fiscal redistribution alone is not sufficient to generate legitimacy. While these mechanisms can generate substantial fiscal revenues for public investment in education, health, and infrastructure, revenue mobilization alone does not ensure legitimacy. Resourcerich regions often receive large fiscal transfers, yet persistent inequalities in service provision remain. In addition, revenue volatility complicates subnational planning: downturns constrain spending abruptly, while boom periods can encourage short-term or inefficient allocation decisions.9 This helps explain why perceptions of unfairness persist even in the presence of formal redistribution. Countries have made efforts to improve accountability and communicate the benefits of extraction. Colombia, Ecuador, and Peru participate in the Extractive Industries Transparency Initiative (EITI), and several governments have developed online transparency platforms to track royalty revenues and public investment.10 Nonetheless, these initiatives often do not translate into effective public understanding, as citizens struggle to interpret or use this information. In this sense, social license depends not only on how the benefits of extraction are distributed, but also on whether the institutions governing extraction are perceived as fair, transparent, and responsive. As the energy transition accelerates, strengthening these institutions may prove just as important as expanding mineral production.

From Rocks to Renewables: Will Critical Minerals Constrain the Energy Transition?

Conclusion Physical scarcity is unlikely to be the decisive obstacle to the clean energy transition. As the history of oil demonstrates, technological innovation, market incentives, and institutional adaptation can expand resource supply well beyond what geology alone would suggest. The greater challenge is therefore not whether critical mineral extraction will increase, but whether it can be governed in ways that are socially accepted, environmentally responsible, and institutionally credible. The evidence from the Andean region suggests that communities are not inherently opposed to mining. Rather, they demand meaningful participation, fair benefit sharing, environmental responsibility, and transparent governance. Social license should therefore be understood as an integral component of project development rather than as a secondary consideration. Likewise, revenue-sharing systems are more likely to gain public support when they are perceived as fair, transparent, and capable of generating visible local benefits. These findings point to the central role of institutions. Strengthening environmental regulation, local government capacity, and mechanisms for consultation and transparency before mining activity expands can reduce conflict while supporting investment. Ultimately, the success of the clean energy transition will depend not only on the availability of critical minerals, but also on the institutions that govern them. The mineral backbone of decarbonization is built not only on geology, but also on trust, legitimacy, and effective governance.

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Notes 1

Morris Adelman, Genie out of the Bottle: World Oil since 1979 (Cambridge, MA: MIT Press, 1995). Daniel Yergin, The Prize: The Epic Quest for Oil, Money, and Power (New York: Simon & Schuster, 1991). 3 Steven Levitsky and Lucan A. Way, “Democracy’s Surprising Resilience,” Journal of Democracy 34, no. 4 (2023): 5–20. 4 Observatorio de Conflictos Mineros de América Latina (OCMAL), Conflictos Mineros en América Latina, database, accessed July 2, 2026, https://mapa.conflictosmineros.net/ocmal_db-v2/ 5 Ingrid E. van Putten, Christopher Cvitanovic, Elizabeth Fulton, Justine Lacey, and Rachel Kelly, “The Emergence of Social Licence Necessitates Reforms in Environmental Regulation,” Ecology and Society 23, no. 3 (2018), https://doi.org/10.5751/ES-10397-230324 6 Lenin H. Balza, Lina M. Diaz, Nicolas Gomez-Parra, and Osmel E. Manzano M., “The Unwritten License: The Societal SLO in Latin America’s Extractive Sector,” Ecological Economics 213 (2023), https://doi.org/10.1016/j.ecolecon.2023.107942 7 Lenin H. Balza, Lina M. Diaz, Nicolás Gómez Parra, Osmel E. Manzano M., and Luis Rodríguez, “Distributive Justice in Mining Royalties,” forthcoming. 8 See:Leandro Gaston Andrian, Gustavo Canavire-Bacarreza, Juan Pablo Jiménez, Jorge Martínez-Vázquez, and Andrés Muñoz Miranda, Dependencia fiscal de los recursos naturales a nivel subnacional en la Región Andina: desafíos y reformas (Washington, DC: Inter-American Development Bank, 2024), https://doi.org/10.18235/0005528 9 Osmel Manzano and Daniela Valdivia, “The Extractive Transition and Social License: The Crossroad for the Andean Region,” in The Political Economy of the Energy Transition in Latin America: Between Extractivism and Sustainable Development, ed. H. Warnecke-Berger and H.-J. Burchardt (Abingdon, UK: Routledge, 2026), https://doi.org/10.4324/9781003678410 10 For example, Colombia's Mapa Regalías provides information on royalty allocations and projects financed through the General Royalties System, while Peru's MapaInversiones tracks public investment projects and budget execution. 2

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National Oil Companies and Latin America’s Oil Boom: Catalysts or Constraints? Francisco J. Monaldi Wallace S. Wilson Fellow in Latin American Energy Policy | Director, Latin America Energy Program

An Overdue Boom Latin America's oil sector is amidst its most consequential transformation in a generation. After two decades of stagnation and decline, the region is now expected to lead global production growth over the next five years. That boom, however, is highly uneven, and the unevenness tracks closely with the institutional quality of the region's oil frameworks and national oil companies (NOCs). Where NOCs operate with commercial autonomy, technocratic management, and durable partnerships with private capital, they have become catalysts of growth. Where governments have treated them as fiscal instruments, social agencies, or tools of political control, they have become the principal constraint on development. Guyana, the only significant regional producer without an NOC, offers an instructive counterfactual for what an unencumbered private sector can deliver.

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Figure 1 — Oil Production in Latin America and US/Canada, 2000–2025

Source: Energy Institute, Statistical Review of World Energy 2026.

For decades, the Latin American oil industry has underperformed. The region missed the oil boom of the 2000s. While U.S. and Canadian production surged on the back of the shale and oil sands revolutions, and Chinese demand pulled global investment toward new frontiers, the region's output stagnated and then, after the 2014 price collapse, fell to its lowest level in three decades. With the notable exception of Brazil, policymakers and investors alike came to see Latin America as a declining oil province. Paradoxically, the region has massive, untapped resources, having the second-largest resource endowment behind the Middle East. Resource nationalism, mismanaged NOCs, and high above-ground risks (expropriation, regulatory and macroeconomic), limited the massive investment potential.

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However, the picture of decline is now out-of-date. Regional crude oil production has been rising for five consecutive years, and most forecasts, including those of the U.S. Energy Information Administration, expect Latin America to contribute more incremental barrels to global supply over 2025–2030 than any other region.1 The reversal has been driven overwhelmingly by two countries operating under different ownership models—Brazil, where Petrobras, a mixed-capital NOC working jointly with international oil companies, executed one of the world's most successful deepwater development programs, and Guyana, where an international consortium, led by ExxonMobil, built an entirely new offshore province with no NOC at all.

Figure 2 — Latin America Oil Resurgence, Production Estimates – 2025 and 2030

Source: Rystad Energy UCube, April 2026

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In addition, two previously underperforming countries are reversing their production decline and could deliver a significant additional upside. Argentina's unconventional Vaca Muerta play has been attracting significant investments under an increasingly pro-market framework that aims to guarantee investors' rights and allow the NOC, YPF, to focus on commercial profitability. Venezuela is recovering from a massive production collapse, through an oil opening to private investment, under the tutelage of the U.S. government, significantly reducing the role of the highly mismanaged NOC, PDVSA.

Divergent Trajectories In 2025, Brazil produced a record 3.8 million barrels per day (b/d), more than double any other producer in the region and a level unimaginable a decade ago. Mexico, still the second-largest producer, produced roughly 1.6 million b/d, continuing a two-decade decline from a peak of 3.4 million b/d. Venezuela, despite holding the world's largest crude resources, produced some 1 million b/d, a fraction of its historical peak. Argentina's crude oil output, concentrated increasingly in Vaca Muerta shale, reached 0.8 million b/d. Colombia produced close to 0.7 million b/d, continuing a gradual decline in reserves and investment. Guyana, which had no commercial production before 2019, averaged roughly 0.7 million b/d in 2025 and has since crossed the 0.9 million b/d threshold, on its way to becoming a top ten global crude exporter by the end of the decade, and it is already the largest per capita oil producer in the world. These trajectories diverge into two groups: countries where the oil sector has been treated as a commercial enterprise insulated from short-term political cycles, and countries where it has been captured by them.

The Structure of the Oil Sector: State Ownership and Its Consequences The political economy of national oil companies (NOCs) is shaped by the structure of the oil sector, i.e., the interaction between resource rents, sunken costs, and geological risks. Oil extraction generates large rents (extraordinary profits), but these rents are highly volatile and heterogeneous across projects, making it often difficult for governments to capture them without over- or under-extracting relative to the optimum. Because oil investments are largely sunken, the NOC (or private investor) can keep producing even after the state appropriates most of the surplus, so long as operating costs are covered, which creates structural incentives for short-sighted governments to over-extract resources.

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These incentives interact with the risk profile of the sector: exploration is highly uncertain, while risk falls once a field reaches the exploitation phase, leading governments and NOCs to prefer low-risk, short-cycle production over long-horizon exploration, and to have incentives to expropriate successful private exploration or frontier projects once uncertainty subsides. In addition, because refined products are politically salient, governments also pressure NOCs to sell domestically below international prices, a form of revenue expropriation distinct from over taxation. Together, large rents, information asymmetries between state and private operators, energy security concerns, and resource nationalism explain why states establish NOCs in the first place, allowing them to maximize short-term rents and monitor private operators while channeling those rents toward politically profitable, non-commercial objectives such as employment, subsidized consumption, and non-oil infrastructure.2 The problem is that pursuing objectives beyond profit maximization make NOCs comparatively inefficient — generating lower profits, revenues, and productivity than private firms — due to wasteful consumption subsidies, weak technical and managerial capacity, corruption, and rent-seeking. Generally, state ownership induces weaker incentives for efficiency and innovation, and higher risks of capture by officials' political goals. But in the case of NOCs those risks are compounded by the structural characteristics of the sector described above. Despite this inefficiency, underperforming NOCs retain control over a large share of global reserves because high rents deliver short-run political benefits that outweigh efficiency losses, particularly where institutions are weak and rent distribution helps sustain political support.3 However, with the right institutional frameworks, some NOCs can be well managed and become catalysts for the development of the oil sector. This requires clear commercial objectives, a competitive environment, a strong institutional framework that limits political interference, and market monitoring. Countries with strong rule-of-law and independent regulatory institutions typically have better-managed NOCs. Similarly, NOCs that have been listed in capital markets have generally performed better. Equinor, the Norwegian NOC, is the gold standard, but there are others that have been run well, including ADNOC (Abu Dhabi), Petronas (Malaysia), and Saudi Aramco (Saudi Arabia). In the case of Latin America, the list includes Petrobras, PDVSA before 2002, and Ecopetrol (although significantly worsening in the last three years).

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Resource Nationalism and Guyana's Counterfactual Majority state ownership of the upstream sector remains the norm across Latin America, as it is in most of the world's hydrocarbon provinces outside of the United States, Canada, the United Kingdom, and Australia. Resource nationalism—the periodic assertion of state control over oil and gas resources, typically in response to rising prices, the end of an investment cycle, or political mobilization around sovereignty—has been a recurring feature of the region's political economy for a century, from Mexico's 1938 expropriation, to Venezuela's 2007 renationalization, to Argentina's 2012 expropriation of YPF from Repsol. What varies is not whether the state asserts ownership of the resource, but whether it allows the operating company—whether an NOC or a private operator—the commercial autonomy and long-term contractual certainty needed to invest at scale; enhancing—instead of constraining—private investment.4 Guyana is the clearest illustration of the alternative model, and its results are difficult to dismiss. With no NOC and a competitive, stable fiscal and regulatory regime, the country went from zero to nearly a million barrels a day of production in under a decade, the fastest ramp-up of a new oil province in modern history. It is not that Guyana has completely avoided resource nationalism because it lacks the political impulse towards it; rather, the absence of legacy state assets and the government's decision to lock in a stable production-sharing framework early removed the principal channel through which that impulse usually expresses itself. Of course, the Guyana experiment could turn wrong if it eventually follows the familiar pattern of expropriation of other countries in the region. But for now, Guyana functions as something close to a natural experiment: it shows what the region's oil sector might look like without the recurring state intervention that constrains investment elsewhere. It is, in that sense, less a template that other countries could easily replicate—none have Guyana's blank slate—than a benchmark against which the costs of the region's more common institutional arrangements can be measured. Its example reaffirms that Latin America’s production gap has not been primarily below ground; it has been above ground, in the institutions that enhance or limit how capital and technology can be deployed.

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Catalysts: Petrobras, and Increasingly, YPF Petrobras is the clearest case. Operating under a mixed-capital model, with a listed minority stake and governance mechanisms that, despite periodic political interference, have preserved a meaningful degree of technocratic control over investment decisions, Petrobras has turned the ultra-deepwater pre-salt basin into one of the most successful deepwater plays in the world. Petrobras's success has not come from the absence of resource nationalism but from a form of nationalism compatible with private co-investment and a long operating horizon. Petrobras was already one of the better-run NOCs when, in 1997, Brazilian President Cardoso eliminated Petrobras's monopoly, partially privatized the company, and created an independent regulatory agency (ANP). The upstream was opened and Petrobras was required to compete in bidding rounds with the international oil companies to acquire exploration blocks. These reforms significantly enhanced the competitiveness of the company and led to its unprecedented success. After the discovery of massive resources in the pre-salt, the Brazilian government became more resource nationalist and the company’s decisions more politicized, which led to a slowdown in growth and some damaging corruption scandals (Lava Jato). However, the following governments relaxed the restrictions on private investment and refocused the company on commercial objectives, significantly improving its performance and outlook. The company is currently executing a 5-year investment plan on the order of $111 billion (a 9% increase over its previous plan), of which US$77 billion is allocated to exploration and production, with roughly 60% of that upstream budget directed to pre-salt assets concentrated in additional floating production platforms for the Santos and Campos basins. The plan targets net production of 3.2 million barrels of oil equivalent per day (boe/d) by 2029, up from 2.69 million boe/d in the third quarter of 2024. Brazil’s national crude output hit a record 3.8 million barrels per day (b/d) in 2025, and Petrobras forecasts operated hydrocarbon output reaching 4.5 million boe/d by 2029—roughly a 10% increase over 2025 levels, with about 80% of production expected to come from pre-salt fields. It earmarks US$45 billion in regular dividends for 2025–2029, with up to US$10 billion more in extraordinary dividends—a reminder that capital-market discipline and a strong institutional framework, not state ownership per se, has maintained Petrobras's focus on its most commercially compelling assets even after the political interference and corruption scandals that damaged the company in the previous decade.5

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YPF illustrates a more recent and still-unfolding version of the same logic. Renationalized in 2012 in a move that, at the time, looked like a textbook case of resource nationalism destroying investor confidence, YPF has since become the leading operator in the Vaca Muerta shale formation, partnering with international operators and increasingly relying on private capital markets to fund its unconventional drilling program. The company is listed in the equity market, where its stock has performed remarkably well. A series of proinvestment reforms—including the Incentive Regime for Large Investments (RIGI) introduced in 2024—has helped stabilize the rules governing large-scale projects and unlock midstream investment in pipelines needed to relieve export bottlenecks. Argentina's crude output is growing faster than that of any other regional producer besides Guyana, exceeding 0.9 million b/d in 2026. YPF’s role in Argentina is best understood as a platform for private investment rather than a substitute for it. Its performance in Vaca Muerta over the past two years is the clearest evidence yet that Argentina’s growth is shale-led rather than dependent on mature conventional fields. In November 2025, YPF reached a historic production record of 200,000 b/d of shale oil—an 82% increase from the 110,000 b/d recorded in December 2023. The company outlined plans to add 50% more company-owned drilling rigs in 2026 with a target of 250,000 b/d. In May 2026, YPF submitted the largest-ever application under RIGI: the US$25 billion development project, involving 1,152 wells over 15 years and a production plateau of approximately 240,000 b/d beginning in 2032. The crude would be exported through the Vaca Muerta Oil Sur pipeline, generating an estimated US$6 billion per year in exports by 2032. These company-level gains sit within a broader national trend: Argentina produced almost 800,000 b/d of oil in 2025, with shale volumes accounting for 63% of oil output and 53% of natural gas output—confirmation that the attractive geology, the RIGI framework and the broader macroeconomic stabilization under President Milei’s government are translating into investment by YPF and its private partners.6 There are still risks that YPF could derail, given the history of mismanagement of state-run companies in Argentina, and the lack of a strong institutional and regulatory framework (in contrast to Brazil). But Argentina has one advantage: instead of the deepwater development with high sunk costs and long-term horizons that require significant institutional credibility, shale development is short cycled, implying that governments have fewer incentives to renege on investment conditions because production would quickly decline.7

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Constraints: Pemex, PDVSA, and Recently, Ecopetrol The mirror image is just as instructive. When governments treat NOCs primarily as instruments of fiscal extraction, employment policy, or political patronage—rather than as commercial enterprises competing for capital—the results are consistent, regardless of the country's geology. Pemex is the paradigmatic case of an NOC turned constraint. Despite sitting atop significant resources that once made Mexico the region's largest producer, crude output has fallen for two decades, from roughly 3.4 million b/d in 2004 to about 1.5 million b/d in 2025. The causes are institutional rather than geological: crushing debt service obligations, a bloated payroll, mandates that prioritize downstream refining projects with poor commercial logic over upstream investment, restrictions on private joint ventures reimposed after 2018, and a tax regime that historically extracted a large share of revenue, severely limiting what the company could reinvest. Pemex is the most indebted major oil company in the world, and its 2025 output was among the lowest in more than four decades, despite the recent massive financial support from the government.8 Pemex's prospects are gloomy; in the first quarter of 2026, it posted a net loss of US$2.6 billion, its worst start to a year since 2020—even as a global oil-price spike triggered by conflict in the Middle East should have worked in its favor. Exploration has been the first casualty: the company completed only 18 exploration wells in 2025, down 46% from 33 in 2024. Instead, capital has been redirected toward costly refining self-sufficiency: it processed 1.1 million b/d of crude in the fourth quarter of 2025, up 44% year-on-year. This politically motivated strategy is economically unsound, because it diverts resources from exploration and long-term production growth to the money-losing downstream. The company has depended on continued state support—US$11.3 billion in financial assistance from the Mexican government in 2025 alone—representing a heavy burden for the public finances. Its dire situation could only be turned around with major institutional reforms and an aggressive opening to private investment, but at this point it looks politically unlikely.9 Venezuela's PDVSA represents an even starker case of institutional collapse. It was one of the better-run NOCs in the world in the 1980s and 1990s, but it was severely damaged by President Chavez’s push to make it a partisan tool for remaining in power. Holding one of the largest resource endowments on the planet, Venezuela produced barely 1 million b/d in 2025—a small fraction of the roughly 3.4 million b/d the country produced in the late 1990s. The collapse of PDVSA’s own operated production (without partners) is even more dramatic, falling to 0.6 million b/d in 2026. 111

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Two decades of politicization following the 2003 oil strike, the exodus of technical talent, chronic underinvestment in its most profitable assets, widespread corruption, and U.S. sanctions; have left the sector requiring tens of billions of dollars in capital to recover. PDVSA is a cautionary illustration of how far a well-run NOC can fall when treated as a political rather than commercial enterprise over a sustained period.10 After the removal of President Maduro in January of 2026, the interim government is attempting a significant oil opening under the tutelage of the U.S. government. The NOC seems destined to become a significantly less relevant player, operating only a fraction of oil production and serving more as a manager of contracts with private companies. That is probably the dominant strategy; the problem is that without deep institutional reforms it may have limited results. Ecopetrol sits between these poles, and its recent trajectory is a reminder that institutional erosion need not start from a position of weakness. Long regarded as a relatively wellgoverned, partially privatized NOC, Ecopetrol has faced rising headwinds since 2022: restrictions on new exploration contracts tied to the current government's energy-transition agenda and corporate-governance controversies surrounding board appointments have contributed to a decline in production, reserves, and foreign investment. Colombian output, at roughly 0.7 million b/d in 2025 (down about 25% in a decade), has continued a gradual multi-year decline, and the country's reserve-to-production ratio—already among the lowest in the region—continues to shrink. Natural gas output fell even more steeply, down 35% over the same decade.11 Colombia is not a collapse story like Venezuela, nor a story of chronic mismanagement like Mexico. It is a case of a well-governed NOC—majority state-owned but listed on the NYSE, with a private float and market discipline—whose national production trajectory has nonetheless deteriorated sharply over the last few years for reasons that are more political than geological (although the country is endowed with limited resources). Unlike the case of PDVSA, the technical and managerial competence that made Ecopetrol one of the region’s better-run NOCs has not disappeared. This is why Colombia is a pivotal case rather than a simple cautionary tale: the newly elected government has pledged to reopen exploration and production contracts, fast-track fracking pilots, and restructure Ecopetrol’s leadership around a commercial mandate. It remains to be seen if this is done with a long-term institutional perspective or by following a partisan strategy. The future of Colombia’s oil sector hangs in the balance.

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Policy Implications Some key implications follow for policymakers and investors navigating the region's boom. Ownership structure per se—NOC versus private concessionaire—is a weaker predictor of sector performance than the credibility of the institutional and regulatory framework surrounding it; Petrobras and Guyana's international consortium have both thrived under very different ownership models, precisely because both have operated under durable rules. These two countries are likely to continue being the best performers, although there are downside risks if either becomes resource nationalist as their exportable surplus rises and if there is a prolonged high-price cycle. Venezuela and, to a lesser extent, Mexico—the region's two largest historical producers— represent the largest upside for regional supply growth precisely because they are furthest from their productive potential; the pace and durability of institutional reform in each will probably matter more to the region's medium-term production trajectory than any single new discovery. At this point, Venezuela is much more likely to add barrels given that it is aggressively opening to private investment. Argentina also has significant upside potential, given its large unconventional resources, if its recent regulatory and macroeconomic reforms are politically sustainable. Latin America's oil boom is real, and it is likely to continue reshaping global crude balances over the next decade. Whether it is sustained, however, will depend less on subsurface geology than on whether the region's governments—and their national oil companies—can resist the pull of the resource-nationalism dynamic that has undone previous booms.

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Notes 1

U.S. Energy Information Administration (EIA), “Brazil, Guyana, and Argentina Support Forecast Crude Oil Growth in 2026,” Today in Energy, December 17, 2025; Rystad Energy, UCube, April 2026; Energy Institute, Statistical Review of World Energy 2026 (London: Energy Institute, 2026). 2 Monaldi, F. (2020). The cyclical phenomenon of resource nationalism in Latin America. In Oxford Research Encyclopedia of Politics. Oxford University Press, New York. 3 Hartley, P. and Medlock, K. (2008). “A model of the operation and development of a national oil company”. Energy Economics 30 (5); Victor, D., D. Hults, and M. Thurber (2012), Oil and Governance: State-Owned Enterprises and the World Energy Supply. Cambridge University Press. https://doi.org/10.1017/CBO9780511784057 4 Monaldi (2020) 5 Petrobras, 2025–2029 Strategic Plan (Rio de Janeiro: Petrobras, 2025); Agência Nacional do Petróleo, Gás Natural e Biocombustíveis (ANP), production statistics; Energy Institute (2026) 6 YPF, 2014 and 2025 Annual Reports; Government of Argentina, Régimen de Incentivo para Grandes Inversiones (RIGI), Law 27,742 (2024); Energy Institute (2026). 7 For a development of this argument see: Collins, G., M. Jones, J. Krane, K. Medlock and F. Monaldi (2021) “Shale Renders the ‘Obsolescing Bargain’ Obsolete: Political risk and foreign investment in Argentina's Vaca Muerta.” Resources Policy, Vol. 74, December. 8 PEMEX, Quarterly Results Report (Mexico City: Pemex, 2026); Energy Institute (2026) 9 PEMEX (2026); Energy Institute (2026). 10 Hernandez, I., C. De Luca, J. La Rosa and F. Monaldi (forthcoming 2026) “The future of PDVSA: Challenges for the reconstruction of the oil sector in Venezuela” Working Paper, Center for Energy Studies, Baker Institute; Hernandez, I. and F. Monaldi (2016) “Weathering the Collapse: An Assessment of the Financial and Operational Situation of the Venezuelan Oil Industry” (with I. Hernandez). Center for International Development Working Paper #327. Harvard University; Energy Institute (2026). 11 Ecopetrol S.A., 2025 Annual Report (Bogotá: Ecopetrol, 2026); Colombian National Hydrocarbons Agency (ANH), reserves and production statistics, 2025; Energy Institute (2026).

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The Rise of Neuquén to Preeminent Petro-Province Status and the Governor Who is on Track To Lead It Through 2031

Mark P. Jones CES Lead, Argentina | Joseph D. Jamail Chair in Latin American Studies

Introduction Argentina is a federal republic within which the country’s 23 provinces enjoy a prominent level of autonomy in regulating the exploration and production of hydrocarbons within provincial borders.1 While historically Argentina had multiple petro-provinces that were important actors in the country’s upstream oil and gas sector, the boom associated with the Vaca Muerta shale play has increasingly concentrated oil and natural gas exploration and production in one province, Neuquén. This reality has converted Neuquén’s 2027 gubernatorial election into a contest of profound salience for Argentina’s energy sector, with the outcome determining whether or not there will be continuity or change in the provincial level policies governing oil and natural gas production in the province that is now responsible for more than two-thirds of Argentina’s hydrocarbon production.

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The Vaca Muerta and Argentina’s Rise in Oil and Gas Production While geographically the Vaca Muerta formation extends across four Argentine provinces (Neuquén, Río Negro, Mendoza, La Pampa), it is centered in Neuquén. As investment in exploration and production in the Vaca Muerta has increased over the course of the past decade, Argentina has witnessed a dramatic rise in unconventional oil and natural gas production and a dramatic decline in conventional oil and natural gas production.2 This shift has resulted in one clear winner (Neuquén) among the provinces which prior to the shale revolution were considered major players within the country’s hydrocarbon industry. Figures 1 and 2 underscore the transformation of Argentina’s oil and natural gas production from a context of multiple prominent provincial players to one where Neuquén increasingly overshadows all of the other provinces, a trend which is not expected to diminish any time soon.3 Argentina produced 18.71 million barrels of oil in March of 2010. At that time, four provinces accounted for more than 10% of Argentine oil production, led by Chubut (28%), and followed by Santa Cruz (21%), Neuquén (21%) and Mendoza (15%).[iii] The remaining 15% of oil production was spread across the provinces of Río Negro (6%), La Pampa (4%), Tierra del Fuego (2%), Salta (2%) and national (offshore, beyond 12 nautical miles) production (1%).

Figure 1 — Proportion of Argentine Oil Produced by Province, 2010-2026

Source: “IAPG Estadísticas,” from the Instituto Argentino del Petróleo y del Gas (IAPG) Note: Data are for March of each year.

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Argentina produced 26.92 million barrels of oil in March of 2026, a 44% increase from March of 2010. Neuquén now produces 69% of the country’s oil, up from 21% in 2010, with Chubut (13%) the only other province that continues to account for more than 10% of Argentine oil production, though less than half the proportion (28%) accounted for in 2010 by the province where Argentina’s oil industry was born back in 1907. The remaining 18% of oil production is spread across Santa Cruz (7%, down from 21% in 2010), Mendoza (6%), Río Negro (3%), La Pampa (1%), and national (offshore) production (1%). Finally, during the current decade Neuquén’s share of Argentine oil production has been on an upward trajectory, increasing from 31% in 2020, to 45% in 2022, to 56% in 2024 to 69% today. Argentina produced 3.94 million cubic meters of natural gas in March of 2010. At that time, Neuquén (47%) accounted for close to one-half of the country’s natural gas production, followed by two other provinces in the double digits, Salta (12%) and Santa Cruz (10%). The remaining 31% of natural gas production was spread across Tierra del Fuego (9%), Chubut (7%), national (offshore) production (7%), Mendoza (5%), Río Negro (2%), and La Pampa (1%).

Figure 2 — Sour Proportion of Argentine Natural Gas Produced by Province, 2010-2026

Source: “IAPG Estadísticas,” from the Instituto Argentino del Petróleo y del Gas (IAPG) Note: Data are for March of each year.

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Mark Jones

Argentina produced 4.39 million cubic meters of natural gas in March of 2026, an 11% increase from March of 2010. Neuquén (71%) now accounts for close to three-fourths of Argentina’s natural gas production, followed in the double digits only by the national (offshore) production at 13%. The remaining 16% of natural gas production is spread across Santa Cruz (5%, down from 10% in 2010), Chubut (4%), Río Negro (2%), Tierra del Fuego (2%), Salta (2%, down from 12% in 2010), and Mendoza (1%). Finally, during the current decade Neuquén’s share of Argentine natural production is on an upward trajectory, increasing from 54% in 2020, to 55% in 2022, to 67% in 2024 to 71% today.

Neuquén Politics Between 1983 and 2023, Neuquén always was run by a governor who belonged to the Movimiento Popular Neuquino (MPN), a provincial political party that competes only in Neuquén. Rodolfo “Rolo” Figueroa had been a long-time member of the MPN, including serving as a MPN mayor (of Huinganco and of Chos Malal), a MPN provincial legislator, the MPN lieutenant governor between 2015 and 2019, and as a MPN national deputy. In 2022 however, Figueroa and his supporters left the MPN and spearheaded an alliance of parties and leaders who had occupied a second-tier status in a province where the MPN had been dominant, and Peronism (Argentina’s largest political movement) was the principal opposition. In the April 2023 gubernatorial election, Figueora (37%) defeated the MPN’s Marcos Koopmann (34%) by 3 percentage points, with the Peronist candidate, Ramón Rioseco (13%), finishing a distant third. Under Neuquén law, Governor Figueroa has broad authority to schedule the 2027 election at a date of his choosing between January and November. At the present time, the most likely date for the election will be between June and September, well ahead of the presidential and national legislative elections that will be held on October 24. Figueora’s first two and a half years in office have been very successful. A recent nationwide survey by CB Consultora ranks Governor Figueora as the second most popular governor in Argentina,5 with 54% of Neuquén residents having a positive opinion of him and 42% a negative opinion. In sharp contrast, Argentine President Javier Milei, who also is up for reelection in 2027, is viewed positively by 38% of Argentines and negatively by 60%.

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In addition to Figueroa’s popularity among Neuquén voters, his re-election prospects are bolstered by a weak and divided opposition at the provincial level. The MPN has yet to recover from the historic loss it suffered in 2023, and many of its most important leaders have shifted their allegiance to their former brother-in-arms Figueroa. Peronism in Neuquén is beset by serious infighting and increasingly tepid support among Neuquén voters. Finally, Milei’s La Libertad Avanza (LLA) has yet to establish strong roots in the province, and given Milei’s pragmatic working relationship with Figueora it is uncertain to what extent the president would support a LLA candidate running against Figueroa, with a LLA gubernatorial candidate also unable to benefit from Milei’s coattails, since the presidential and gubernatorial elections will not be held concurrently.

Conclusion Neuquén represents the present and the future of Argentina’s oil and natural gas industry, having gone from being one of several important petro-provinces to the country’s dominant petro-province. Neuquén accounts for well over two-thirds of the Argentina’s hydrocarbon production, and it is on track to account for three-fourths by the end of the decade. And, while there is uncertainty about who will serve as Argentina’s president between December of 2027 and December of 2031, there is little doubt today that energy policy in the province of Neuquén will remain through the end of 2031 under the reliable stewardship of Governor Rolando “Rolo” Figueora.

Notes 1

See Collins, G, M. Jones, J. Krane, K.B. Medlock III, and F. Monaldi (2020), “Shale Renders the ‘Obsolescing Bargain’ Obsolete: Political Risk and Foreign Investment” Baker Institute Working Paper. in Argentina’s Vaca Muerta,” https://www.bakerinstitute.org/sites/default/files/2020-02/import/fdi-collins-etalargentina.pdf 2 See Siboldi, A., A. B. Micciarelli, and J.L. Ariza (2026), “Argentina – Oil & Gas Laws and Regulations 2026,” https://iclg.com/practice-areas/oil-and-gas-laws-and-regulations/argentina/. 3 Many Argentines are optimistic that eventually the Palermo Aike shale play in the province of Santa Cruz will be able to become a major producer of oil and natural gas, but that is unlikely to be the case for the foreseeable future due to a combination of continued geological uncertainty and relatively high production costs. 4 All oil and natural gas production date contained in the figures and referenced in the paragraphs below come from the Instituto Argentino del Petróleo y Gas website at www.iapg.org.ar. The month of March is used since it is the most recent month for which 2026 data are available, although the use of data from other months or annual data produces similar results. 5 See JUNIO 2026 – RANKING DE GOBERNADORES + RANKING FEDERAL DE INTENDENTES | CB Global Data

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ENERGY AND GEOPOLITICS IN LATIN AMERICA

Unlocking the Potential for an Energy Revolution in Latin America and the Caribbean Lourdes Melgar Nonresident Fellow

Introduction The wars in Ukraine and the Middle East have disrupted energy markets defying long-held assumptions and exposing critical vulnerabilities in the foundations of energy security. The reorientation of American foreign policy has added uncertainty and volatility, eroding the trade and investment architecture that supported capital flows for decades. Within this highrisk landscape, the natural resource-endowed Latin America and the Caribbean (LAC) region has a unique opportunity to emerge as a strategic anchor in the evolving global energy architecture. Realizing this potential depends on more than just an abundance of oil, gas, critical minerals, and rare earth elements. To transform natural resource wealth into resilient inclusive development, LAC needs a vision derived from the convergence of resource wealth, technological innovation, and geopolitical reconfiguration. LAC could define an innovative development path that embraces its own priorities—such as social justice, environmental stewardship, energy democratization, and sovereignty—while raising its global geopolitical influence.

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To this end, the region must avoid the pitfalls of previous development strategies that reinforced its position as a dependent periphery supplying commodities to other industrialized economies. It is therefore important to design and implement stable and resilient institutions, predictable legal and regulatory frameworks, and state-of-the-art policies that enable moving beyond failed models of the past toward 4D energy systems (Decarbonized, Decentralized, Digitalized, and Democratized). Navigating this shift requires strategic vision, pragmatism, and a firm commitment to a renewed social compact based on public-private-social consensus to ensure the legitimacy of the new paradigm and the equitable distribution of benefits. To reshape the LAC energy and economic development trajectory, the region's energy resource endowment checks one necessary box, but sufficiency requires dealing with political-economy barriers and climate vulnerabilities. Sustainable growth, energy security, and social inclusion are important to constituents across the region. These pillars are fundamental to driving regional prosperity and establishing LAC as a stable, trusted partner in international energy and critical mineral markets.

Resource Wealth, Strategic Assets, and Emerging Momentum LAC holds some of the largest petroleum resources outside the Middle East, including Venezuela's vast oil reserves, Brazil's offshore pre-salt fields, Guyana's rapidly expanding offshore sector, Mexico's proven reserves and prospective resources, and Argentina's unconventional shale resources in the Vaca Muerta formation. The region also contains substantial technically recoverable shale resources, led by Argentina, with Brazil, Mexico, Paraguay, Colombia, and Bolivia among potential contributors. LAC accounts for roughly one-tenth of global oil supply and holds significant future production potential. The same is true for natural gas. Currently, LAC is a regional market with liquefied natural gas (LNG) imports—largely from the United States but also Qatar and intraregional partners —into Brazil, Argentina, Mexico, Chile and the Caribbean. At the same time, Trinidad & Tobago and Peru export LNG to neighboring LAC countries as well as to the buyers in Europe and Asia. This occurs despite the LAC holding a sizeable regional natural gas endowment paired with relatively modest consumption. A fortified producer base could see expanded production and a shift to greater exports, while enhancing regional energy security and supply resilience. However, sustained capital investment and predictable regulatory frameworks are essential for LAC to solidify its position as a trusted and dependable supplier. 123

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While fossil fuels remain strategically relevant, LAC is also well-positioned for new and lower carbon energy technologies. Supported by countries with high shares of clean electricity generation, LAC has one of the lowest-carbon intensity energy mixes globally. In addition to its well-known hydroelectric and biofuel production and potential, the region has world-class solar photovoltaic and wind potential, as well as opportunities for geothermal. Through competitive procurement and other policy mechanisms, LAC has added substantial solar and wind capacity in recent years. With few exceptions, capacity factors for already deployed solar and wind technologies are strong across the region, with Brazil among the countries with particularly high performance. The region also holds an estimated 55 GW to 70 GW of geothermal potential, with Mexico, Chile, El Salvador, and Costa Rica leading in operation and development. It also produces a significant share of the world's biofuels, most notably in Brazil, which has been a leader in this sector since the 1970s. In addition, South American countries are venturing into green hydrogen, most notably Chile. The region’s resource endowment provides a diversified platform from which to advance electrification, industrial competitiveness, and low-carbon growth. Of course, market design, supportive policy, and regulatory certainty are critical to attracting the necessary capital investment. Accelerating the transformation of energy systems, scaling renewables and advancing clean mobility will require substantial investment in grid modernization, transmission expansion, distributed generation, storage, and the development of robust supply chains capable of supporting a sustainable industrial base. Thus far, investment in transmission, smart grids, and supply chains has not kept pace with the scale of the region's renewable-resource potential, limiting LAC's ability to fully capitalize on its advantages. The upstream end of low carbon energy systems also begins in the region. Critical minerals and metals are another facet of LAC’s tremendous resource wealth, constituting a clear linkage to industrial strategy.1 The region is a major supplier of copper, lithium, silver, graphite, tin, zinc, and other strategic minerals, holding substantial shares of global lithium and copper reserves, as well as significant rare-earth elements in Brazil and Chile. This resource base positions LAC to play a strategic role in the value chains underpinning electrification, battery storage, renewable power, advanced manufacturing, and the new digital economy.2

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Lourdes Melgar

However, since colonial times, LAC has attracted substantial mining investment but has struggled to develop integrated industrial capabilities around mineral extraction. The region risks reproducing a commodity-dependent development model that limits the benefits of its resource endowment. Already China, the United States, and leading transnational mining companies dominate LAC’s market of raw critical minerals. The region’s strategic position will depend less on extraction alone than on its capacity to capture value through refining, processing, technological innovation, and regional supply-chain integration. Fostering these capabilities would allow the region to strengthen the security of global critical-mineral supply chains, while advancing domestic industrial upgrading, employment, and more resilient development pathways.

Political-Economy Barriers The current great energy and digital interregnum, unleashed by the fourth industrial revolution, presents profound risks for those who fail to embrace the opportunity to rethink and recast development paths. Imagining viable alternative futures for LAC’s energy sector requires uncovering its political-economy underpinnings, as well as its contending political beliefs and objectives, to identify the structural and ideological barriers that stall change. Countries in the LAC display persistent tensions between political agendas and international activism in environmental and climate agendas. Given the regional vulnerabilities to climate change, the LAC has played a pivotal role in international climate negotiations, advocating for ambitious targets and international financing for adaptation and low-carbon transitions. At the same time, national revenue and gross domestic product rely heavily on the extractive industries and industrial agriculture. So, despite the LAC’s rhetoric and collective low carbon energy potential, the region remains fossil-fuel dependent for energy and as source of revenue. Currently, two-thirds of LAC energy supply comes from hydrocarbons. On average, oil and gas account for 2.1% of GDP across the region, although there are significant differences between petrostates (Venezuela, Ecuador, Bolivia and Trinidad and Tobago) and strategic producers (Brazil, Argentina, Colombia and Mexico) in terms of fossil-fuel economic reliance. Hence, there is a continuous strain to reconcile long-term environmental aspirations with macroeconomic priorities.

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Although these tensions have produced a backlash against an accelerated energy transition, the narrative and the legal architecture around environmental commitments endure, advancing legal obligations, most recently through the ground-breaking Escazú Accord. As the first regional treaty for climate justice, it aims to protect environmental defenders and guarantee public access to information and decision-making. By empowering local communities, the Accord directly targets the structural inequalities that historically excluded local communities from energy governance to provide a legal counterweight to state-centric resource nationalism. While economic dependency on extractive industries is structural, it is also inherently political; the region maintains a powerful commitment to resource nationalism, where the defense of fossil-fuel sectors serves as the ultimate proxy for national sovereignty. Mexico is the quintessential example of the backlash against the liberalization of the energy sector and the acceleration of the energy transition. The failure to build consensus from the bottom up is compounded by deep-seated structural inequality. In turn, this has resulted in a constant redefinition of the rules of the game and failed efforts to productively reform the industry, leading to the decline of investment and domestic production. Brazil offers a parallel case of regulatory instability, driven by the same political conundrum. The country swung from an initial liberalization starting in 1997 to a state-centric retrenchment under the Lula and Rousseff administrations—who mandated that Petrobras act as sole operator—before reopening and divesting under the Temer and Bolsonaro governments. Nevertheless, despite this ideological pendulum, the technical complexity of frontier offshore resources coupled with an outward facing national oil company—Petrobras —and the opportunity for international energy companies to expand their reserve portfolios, Brazil has successfully grown its upstream activities. It entered the ranks of a top 10 global producer in the 2010s, and it is projected to produce 5 million barrels of crude oil per day by 2030.3 A similar dynamic plays out in the mining sector, where rigid resource nationalism has historically delayed industrial growth. Where good governance and pragmatism have prevailed, such as in Chile, raw minerals production has thrived. However, even successful models like Chile's reveal structural gaps, as the country has failed to develop integrated advanced manufacturing, effectively exporting the primary value creation of its resources overseas.

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Lourdes Melgar

Among the structural challenges LAC faces is its vulnerability to climate change, water scarcity, and deeply entrenched socio-political inequality. While environmental crises threaten physical infrastructure, persistent inequality limits public buy-in for transformative energy policies. LAC features one of the cleanest electricity sectors, as over 65% of its generation is derived from renewable energy sources, primarily large hydropower plants built in the 20th century. However, seasonal water shortages are increasingly met with fossilfuel thermal generation, often natural gas. This reliance raises regional emissions and undermines compliance with the Nationally Determined Contributions under the Paris Accord. The alternative of mitigating seasonal hydropower downturns with renewables is limited by the lack of transmission infrastructure, the fragile resilience of the energy system, a lack of storage, and social barriers to the rapid deployment of infrastructure. The Global Map of Environmental Justice (EJAtlas)4 shows the LAC region is dense with persistent energy, mining, water and infrastructure conflicts. This systemic opposition stems from a profound sense of dispossession regarding land and economic benefits, compounded by the lack of meaningful community participation in territorial decisions. Ultimately, the pursuit of social and environmental justice remains a historical imperative in a region burdened by the world’s highest GINI coefficient.5 To address these systemic gaps, LAC nations have embraced legal instruments such as ILO Convention 169, which mandates prior and informed consent from indigenous populations,6 and the Escazú Accord, which has become major instruments for communities striving to reclaim their territorial rights.7 Nonetheless, there is a sharp disarticulation between narrative and reality. With few exceptions, consultation processes are often simulated or short-changed, and compensation remains symbolic, planting the seed for instability and heightened risks for capital intensive projects. These structural barriers and socio-political conflicts have interrupted the energy sector’s development. The return of an orthodox form of resource nationalism, taking as reference the glories of the past century, has further stalled unlocking the full potential of the region, limiting governments’ capacity to deliver on their promises of energy security, energy affordability and economic growth. The time has come to rethink and redesign the governance of the region’s energy systems.

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Redefining Paradigms Given the current, highly volatile geopolitical landscape, LAC nations have a historic opportunity to reshape their development path. Success requires aligning socio-political ambitions with natural resource governance, evolving 20th-century resource nationalism into a flexible, pragmatic approach driven by technological innovation, cost-effective solutions, and real local community stakeholder engagement. This requires vision, political will, consensus building, and a fundamental redefinition of the social contract. LAC governments face a defining moment to leverage their position and redefine the investment paradigm to foster structural modernization, build a sound industrial base, and democratize energy choice, all rooted in economics, environment, and social impacts.8 While the task ahead may seem daunting, it primarily requires aligning principles with action and adopting best practices that have proven successful in other regions. LAC also has the unique opportunity to leapfrog, bypassing structural hurdles that European nations encountered in their transition to a low-carbon economy. To succeed, the region must implement long-term plans, with a clear roadmap to transform the local industrial base, thereby optimizing value capture of its massive and diverse resource base. Two upfront tensions drive the social conflicts impacting energy and mining projects: the redefinition of the social contract and the socio-political dilemmas of energy transitions. Regarding the social contract, local communities are demanding engagement as full participants in the decision-making process and benefit-sharing mechanisms of new industrial scale projects. Regarding socio-political dilemmas, with limited exceptions, governments and markets have failed to develop economically viable plans for a macrolevel transition to low-carbon energy without compromising reliability, cost, and social impact. To be clear, an abrupt halt to fossil fuel production in the LAC remains unrealistic. As such, given regional NDCs target net-zero by 2050, the LAC will be pushed to ensure hydrocarbon production meets the highest environmental standards. This will include strict compliance with the World Bank’s Zero Routine Flaring Initiative and Global Methane Pledge (30% reduction by 2030). This will require transparency and enforcement of rigorous technical and managerial requirements for reservoir and quarry development, all while driving local value capture and job creation in emerging industries.

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Although reducing fossil fuels use in electric power may seem formidable, moving the electricity sector into 4D energy systems can unlock significant opportunities. Countries in the LAC have already made significant strides through innovative electricity market designs and renewable energy auctions, yielding record low prices and rapid wind and solar deployment. Some countries are also actively advancing electromobility, hybrid transit, and green hydrogen roadmaps, alongside robust net-zero policies, energy efficiency regulations, and biodiversity conservation initiatives. Taken together, these types of approaches can yield substantial benefit. However, LAC energy systems generally remain grounded in 20th-century network and market designs and face infrastructure bottlenecks—particularly in grid development—that limit the benefits of the region's renewable endowment. To overcome this, the LAC can transform its energy architecture through digitalization and state-of-the-art technologies to build a modernized, highly reliable, resilient, and deeply interconnected pan-regional electricity sector. None of this is possible without the legal certainty global markets demand. So, LAC governments must implement clear, stable policy frameworks, and institutionalize robust public-private compacts. Implementing these mechanisms remains the decisive pathway to mitigating socio-environmental conflicts, attracting large-scale infrastructure financing, and catalyzing a 4D energy revolution. Ultimately, this could transform the region from one whose commodities are dependent on commodity exports into a resilient, high-value 21stcentury industrial powerhouse.

Notes 1

International Energy Agency (2026). Global Critical Minerals Outlook 2026. IEA Publications. Organisation for Economic Co-operation and Development (2026). Regional Note on Critical Minerals in Latin America and the Caribbean. OECD Publishing. oecd.org 3 International Energy Agency (2023). Latin America Energy Outlook 2023: World Energy Outlook Special Report. IEA Publications. iea.org. 4 Environmental Justice Atlas (2026). Global Atlas of Environmental Justice: Mining and Energy Conflicts in Latin America and the Caribbean. ICTA-UAB. ejatlas.org 5 World Bank (2026). LAC Equity Lab: Income Inequality - Inequality Trends (GINI Index). World Bank Group. worldbank.org 6 International Labour Organization. Indigenous and Tribal Peoples Convention, 1989 (No. 169). ILO. 7 United Nations (2018). Regional Agreement on Access to Information, Public Participation and Justice in Environmental Matters in Latin America and the Caribbean (Escazú Accord). United Nations. 8 See Meidl, R. and K. B. Medlock III, “The Pride and Prejudice of Sustainability: Rethinking Sustainability from a Systems Perspective,” Rice University's Baker Institute for Public Policy (Nov 8, 2023). DOI: 10.25613/20CH3Z48. 2

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ELECTRICITY MARKETS AND POLICY

Power Sector Challenges

Peter R. Hartley CES Lead, Electricity

Introduction The developing world has long faced formidable challenges in delivering affordable gridbased electricity to rapidly growing populations aspiring to partake of the benefits of modern technology and modern lifestyles. The developed world, by contrast, had become so used to having access to reliable and affordable electricity that it had become complacent about those goals focusing instead, almost exclusively, on controlling emissions from fossil fuel combustion. Not only that, but the relevant governments rejected the recommendation of environmental economists that emission taxes are the most effective instrument to control emissions and have instead focused on “command and control” measures that “pick winning technologies” – in this case, wind and solar generation (together classified as variable renewable energy, or VRE). This is despite the fact that if one ranks countries in the Energy Institute Statistical Review of World Energy1 by increasing percentage of fossil fuel in the primary energy mix, the first dozen or so countries on that list all have relatively high percentages of nuclear power and/or reservoir-based hydroelectricity, not wind or solar. The ability to use reservoir-based hydroelectricity is limited by geography and climate. On the other hand, any advanced economy can safely deploy nuclear technology. Furthermore, as Qvist and Block note,2 the French and Swedish nuclear programs provide the main historical examples of the bulk displacement of fossil fuels. Except where substantial hydroelectric capacity based on stored water is available, once VRE increases beyond about 20% of generation output, additional VRE becomes very difficult to accommodate without incurring substantial increases in electricity prices and degradations in reliability. Those experiences belie the oft-repeated claim that VRE is “the cheapest form of generation.”

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That claim is based on a comparison of the levelized cost of electricity (LCOE), but LCOE is a poor guide to the actual costs incurred as different types of generation are added to the network. Instead, “levelized full system cost of electricity” (LFSCOE)3 is a better guide.

LCOE Is an Insufficient Metric To begin, LCOE measures average costs at the electrical bus that connects the generator to the network. However, the value of the electricity at that point is zero. Any positive cost exceeds the benefit. Electricity only has value when it is delivered to customers, which requires transmission lines at a minimum. Since wind and solar are diffuse energy sources, substantial land is required for their installation. This favors installing them in locations with low land costs, which are often remote from loads. The long lines are expensive to install and have high impedance, which requires compensating investments. Lines capable of transmitting maximum VRE output are expensive, but lower-capacity lines require VRE generators to be curtailed, further reducing their already low-capacity factors. Transmission lines serving VRE are also used at the same low-capacity factors as the generators themselves. Furthermore, more than transmission lines are needed to deliver generated electricity to customers. A working electricity network requires a continual fine balance between supply and demand, and continual interventions to maintain frequency, voltages, and reactive power within fine tolerances. Only dispatchable plants can supply those services. The first type of additional generation cost is termed “adequacy impacts.” Additional generating capacity is needed to meet peak demand when VRE is not producing. Episodes of limited output from VRE include daily and seasonal cycles in incident solar radiation and wind speed, and the “dunkelflaute” events of simultaneous low wind speed and cloudy weather that accompany slow-moving high-pressure cells at 40-50° latitudes during winter months. Such episodes require backup capacity to ensure supply is adequate to meet demand. However, that backup capacity is not used when VRE is generating, thereby reducing its capacity factor and raising average costs by making capital use less efficient. The erosion of demand for backup plants also tends to favor peaker over baseload plants, which raises operating costs.

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Peter R. Hartley

Another problem with VRE is that its output varies substantially over very short intervals. For example, a 10% change in wind speed can lead to a 30% variation in power output. More standby capacity is needed to keep the system balanced, which raises ancillary service costs. A related problem highlighted by the blackout on April 28, 2025 in the Iberian Peninsula is that systems dominated by VRE output have low inertia. In a power system with synchronized, heavy, rapidly rotating turbines, the effects of small frequency disturbances tend to be automatically and very quickly counteracted. By contrast, VRE generators are connected to the system by grid-following inverters that rely on the rest of the system to set and maintain frequency. Grid-forming inverters are available and have been used in microgrids to set the alternating current frequency. However, it would be unacceptably risky to rely on a single grid-forming inverter to set and maintain frequency in a large system, while configuring inverter software to ensure that multiple grid-forming inverters can work together effectively under all types of disturbances remains an unsolved problem.

Demand, VRE, and Transmission The growth of AI and data center demand have increased the demand for reliability. While bitcoin mining operations and AI model training are exceptions, many of the burgeoning AI and data center operations demand levels of reliability in the 99.99–99.999% range. The electricity system that supplies most of the state of Texas (ERCOT) illustrates some of these problems. For at least the last 16 years, dispatchable thermal capacity in ERCOT has remained roughly constant while load has grown at around 2% annually. From 2010-2017, wind generators supplied almost all the net capacity increase. In the next 7 years, wind and solar together did so. In the last few years, battery capacity has had the highest percentage growth rate, but from a very small base. Batteries are dispatchable when charged, but they typically supply power for only a few hours. While new natural gas generators have been added to ERCOT over this period, their added capacity has barely offset the retirements of coal and older single-cycle steam generators that use natural gas as their fuel. The result has been that in recent years, load has exceeded dispatchable capacity for more than 1,100 hours per year. Since ERCOT has only weak connections to neighboring systems, operators must hope that those periods do not coincide with low VRE output. In a recent paper,4 we examined locational marginal prices (LMP) in ERCOT measured at more than 16,500 locations every five minutes for 152 days in the summer and fall of 2023 to assess some of the effects of VRE. 133

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There are two components in each LMP. The first is a “marginal energy price” or the “shadow price of power balance” that is common to all the LMP calculated each period. The second, which is unique to each LMP in each period, is a “transmission congestion component.” The latter reflects the marginal impact of changes in net demand at each location on any binding transmission constraints. Specifically, the congestion component is positive if demand increases at a location tend to exacerbate binding transmission constraints, and conversely, it is negative if supply increases at the location exacerbate the binding constraints. LCOE calculations for VRE generators assume that they have zero marginal operating costs. An increase in load met by an equal increase in VRE output should then have no effect on the marginal energy price. Instead, we found that a 1000 MW increase in load matched by a 1000 MW increase in wind increased the shadow price of power balance by about $2.65/MWh on average. For solar, the average increase was about $1.65/MWh. The implication is that supplying load with increased VRE output requires a re-scheduling of thermal generators to maintain system balance such that the lowest marginal cost thermal generators are no longer supplying the marginal output. These costs are a substantial fraction of the average increase of $4.65/MWh when the 1000 MW increase in load is matched by a 1000 MW increase in thermal generation. The marginal cost advantage of VRE that is reflected in LCOE calculations evidently tends not to be realized in practice in ERCOT. These results also imply, for example, that a 1000 MW increase in wind output that is accommodated by a 1000 MW decrease in thermal output (so load remains unchanged) saves only about $2/MWh on average Another surprising result is that an additional 1000 MW of “physical response capability” (PRC) in the 5-minute interval prior to when the marginal energy price is measured reduces that marginal energy price by about $7.70/MWh on average. ERCOT defines PRC as “the generation and load resources that are available to respond quickly to system events in case of sudden changes, such as an unexpected outage at a large generating unit.” In the period we examined, these were overwhelmingly natural gas plants. Since thousands of congestion components are measured every 5 minutes, systematic patterns in their determinants are harder to discern. The simplest case is when no transmission constraints are binding, and all the congestion components are zero. This occurred in less than 22% of the 44,649 five-minute intervals in our sample.

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After controlling for endogenous curtailment of VRE generation when transmission constraints are binding, we found that meeting increased load with increased VRE increased the probability of experiencing at least one binding constraint by more than (wind 2.5 times, solar 1.5 times) when the load is met by an equivalent increase in thermal output. Although PRC is not scheduled with alleviating transmission constraints in mind, we found that increased PRC in the previous 5-minute interval had a strong negative effect on the likelihood of at least one binding transmission constraint. This suggests that natural gas plants are well-located to serve major loads. By contrast, we found that the most constrained buses in ERCOT tended to be supply buses in regions with substantial wind and solar generation. The resulting large transmission component discounts lead to economic curtailment where operators choose to curtail output to avoid negative prices. We also found that displacing thermal output by increased VRE generation tends to exacerbate transmission constraints, especially in peak load periods. Another surprising result is that transmission constraints tend to be more prevalent and severe in low load periods than in intermediate load periods. Part of the explanation appears to be that increased VRE generation has more severe consequences when the load is low, in which case VRE makes up a larger share of total output.

The ERCOT Experience and Other Regions The discussion thus far has focused on ERCOT because we have studied it more thoroughly than other locations. However, as noted earlier, the problems from increasing shares of VRE in the generation mix are universal. Another instructive example is an event from the National Electricity Market (NEM) in eastern Australia. Broken Hill is a remote mining town in the state of NSW connected to the NEM by a single transmission line. Annual peak demand from the mining operations and the town is about 36 MW. The load used to be served by two diesel-powered gas turbine generators, each rated at 25 MW capacity. After the town was connected to the NEM, local authorities decided to encourage non-fossil fuel generation. A 193 MW wind farm, a 53 MW utility-scale solar array, more than 6000 rooftop solar PV installations providing roughly 35 MW of capacity, and a battery bank with 50 MW generating capacity and 50 MWh storage capacity were installed. Given the extensive solar resources in the desert climate, the region quickly became a major exporter of power to the NEM during daylight hours.

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However, disaster struck in October 2024 when a line of severe thunderstorms destroyed a group of towers on the transmission line. The legacy diesel-powered gas turbine generators had fallen into disuse and thus had been poorly maintained. Only one was operating in October 2024, and then only at a reduced 14 MW capacity. Despite the excessive amount of VRE generation relative to load, most of it was worthless after the disconnection. The wind farm and solar array sat idle as their grid-following inverters didn’t work without the connection to the NEM. The battery bank inverter could be operated in grid-forming mode, but it was almost worthless in practice. The batteries could only serve the evening peak; they were useless until recharged by rooftop solar the next day. The diesel generator provided insufficient inertia to prevent some household PV inverters from disconnecting. Mine and school operations ceased until the link to the NEM was restored. Power was insufficient and too intermittent to refrigerate drugs and fresh food, necessitating expensive daily re-supply measures. Another fundamental problem with attempting to base electricity supply on VRE and batteries is that no one knows how to operate a wholesale electricity market in such a system. In the absence of transmission constraints or losses, when all generation has zero marginal cost, competition will drive marginal energy prices to equal the zero marginal cost. There are no rents to pay for the up-front capital costs. To obtain an efficient outcome, just the “right” amount of monopoly pricing power is needed. A wholesale auction market to achieve that outcome has not been designed. Transmission constraints and losses exacerbate the problem. Unlike thermal generators, VRE generators are location constrained. Typically, the best solar or wind resources are not found in urban areas where the maximum loads occur. Even if they were, VRE generators require large amounts of land because the underlying energy sources are diffuse. This also favors remote locations where land prices are lower. Constructing lines to carry peak VRE output is expensive, especially since the lines are then severely underutilized for much of the rest of the time. Transmission constraints then result in negative prices at the electrical buses to which the VRE generation is connected and positive prices at the buses where loads are connected. Additional investment in batteries to store excess VRE output can alleviate the problem, but that is not cheap. Moreover, batteries cannot solve the other problem of transmission losses. Even in the absence of transmission capacity constraints, incorporating ordinary line losses into LMP would lead to negative prices at the electrical buses to which the VRE generation is connected and positive prices at the buses where loads are connected. Energy Insights 2026

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Symptoms of the underlying problems are manifest in current systems with significant VRE capacity. Wind and solar plants “foul their own nest” when they all generate at the same time and location, thereby depressing the prices they receive. In addition, the revenue VRE generation takes from dispatchable plants leads to a “missing money” problem. Returns to dispatchable plants become insufficient to fund the maintenance expenditures needed to stave off retirements or to incentivize investment in new capacity as old plants retire. Adding “capacity markets” to the wholesale energy market is an ad hoc response with no mechanism to ensure a benefit/cost test for the contracted capacity amounts or types (peak/intermediate/base; dispatchable/non-dispatchable).

Widening the Perspective The recent conflict in the Middle East has again increased the salience of energy security concerns. Those events have impacted the oil market and the natural gas market via constraints on global oil supply and LNG export supply, highlighting the importance of energy security. This raises an important issue for wind and solar generators, and batteries because they have much higher mineral requirements per unit of generating capacity than fossil-fuel-based or nuclear generators. The discrepancy is even larger when mineral requirements are measured per unit of energy supplied over the equipment's life. This is true for two reasons. First, VRE generators have a shorter lifespan. Second, they operate at much lower capacity factors. The energy security implications of higher mineral requirements arise from China’s dominance in processing those minerals. This exacerbates China’s dominance in supplying parts for wind and solar generators. We can expand the focus of the discussion by returning to the issue we began with. Development in large-population countries will inevitably greatly increase energy demand in general, and the demand for electricity in particular. Limiting fossil fuel use in OECD countries alone is largely irrelevant to the continuing global use of fossil fuels. With economic growth as the top priority of these countries, the focus is on affordable energy, with other issues such as reliability, accessibility, energy security, and local pollution ranking ahead of potential future impacts on climates. Alternatives to fossil fuels need to be competitive without subsidies or mandates, and capable of meeting massively expanding demands. VRE does not appear to be viable path for the mass displacement of fossil fuels in electricity generation. Policy and commercial choice is starting to recognize this.

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Notes 1

https://www.energyinst.org/statistical-review/resources-and-data-downloads Qvist, Staffan A. and Barry W. Brock (2015). “Potential for Worldwide Displacement of Fossil-Fuel Electricity by Nuclear Energy in Three Decades Based on Extrapolation of Regional Deployment Data.” PLoS ONE, 10(5): e0124074. 3 Robert Idel, “Levelized Full System Costs of Electricity,’ Energy, Volume 259, 2022, 124905 4 Hartley, Peter, Kenneth B. Medlock, and Elsie Hung. 2026. “Operational Constraints and the Merit Order Effect in ERCOT,” The Energy Journal, Volume 47 (3) 2

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Booming Energy Demand: World War II vs Data Centers Julie A. Cohn Nonresident Scholar

Introduction In April of this year, the Electric Reliability Council of Texas (ERCOT) projected an unprecedented 430% increase in demand over the system’s current peak of 85,508 MW by 2032 – a mere six years from now.1 ERCOT’s filing clarifies that the forecast anticipates a range of outcomes. Nonetheless, the possibility that demand for electricity in Texas could increase so dramatically and so quickly is alarming to many, especially with regard to electricity costs and the reliability of the power system. Stories like this are unfolding across the country.2 For most of the past twenty years, generation of electricity in the United States held steady at about 4 trillion kilowatt-hours per year. Generation started to increase in 2017, and, despite a COVID-related slowing of electricity use in 2020 and 2021, continues to this day as illustrated in Figure 1. Across the US economy, several factors contributed to the rise in electricity generation during the past nine years, including increased popularity of electric vehicles, installation of electric heating in place of gas heating, electrification of manufacturing and industrial processes including oil- and gas-fields, growth of cryptomining, onshoring of manufacturing, addition of large-scale computing resources, and most recently, a burgeoning of hyperscale data centers.3 These data centers house giant computing devices that store and process data to support AI queries from a wide array of entities. In the past, large loads demanded power in the range of 200-800 MW whereas today’s planned data centers may have peaks exceeding 1,000 MW, more than many midsized US cities.4 The challenge posed by recent forecasts is not entirely exceptional. The second World War provides useful context for how Americans have dealt with very high energy demand over a very few years. Energy Insights 2026

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Figure 1 — Annual US Electricity Net Generation, 1948-2025 (Million kWh)

Source: EIA.gov, Total Energy Database, Accessed 5.29.2026. Note: Period of relatively little change indicate by black oval (2005-2017).

Following the first major energy crises experienced in the United States during the first world war, the federal government, utilities, academics, and others weighed approaches to avert similar problems in the future.5 As “war clouds”6 gathered over Europe in the late 1930s, concerns about the sufficiency of the nation’s power systems increased. In July of that year, the Federal Power Commission together with the War Department provided President Franklin Roosevelt with a confidential memorandum indicating that by 1940, just 18 months away, the industry would have to add 1,100 MW more capacity than already under contract to meet domestic demand alone in the country’s 15 principal manufacturing centers (see Figure 2).7 The report anticipated that industry would be further pressed to add nearly five times more capacity in those regions by 1940 in the event of war, a number that resonates with electricity demand from data centers today.

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Figure 2 — Assured vs Projected Capacity Needs in Principal Defense Production Regions, 1938.

Source: Confidential Memorandum on Shortages of Electric Generating Capacity for War-time Needs, Federal Power Commission—War Department to the President.

The utilities themselves projected that domestic demand (comprised of normal industrial expansion, residential use of new electric appliances, rural adoption of electric agricultural implements, and commercial activity) would double in any event by 1948.8 In fact, by 1948, use of electricity increased 2.6 times, with the largest growth among industrial users, including defense manufacturers (see Figure 3). The demand across the US economy, and the wartime responses of both the utilities and federal agencies, offer insights into today’s challenge to meet unprecedented demand. Several key factors frame electrification during the war: Demand did grow, even more than utilities and federal agencies predicted. The power industry responded with a modest increase in generation capacity. Utilities made a major investment in new transmission lines and power pooling. Engineers and system operators developed innovative technologies and operating techniques in order to run plants 24/7 to meet both domestic and war-production demand. Energy Insights 2026

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Figure 3 — Use of Electric Energy by Sector, 1938 to 1945 (Million kWh)

Source: Historical Statistics, Colonial Times to 1970, Series S 120-132, p. 828.

Demand: During the war years, 1941-1945, increased demand resulted primarily from continuous factory operations, characterized by manufacturers running 2 or 3 shifts rather than just one; institution of “War Time,”9 expansion of continuous electro-metallurgical and electro-chemical production,10 and energy requirements of the Manhattan Project.11 Installed Capacity: Installed generating capacity grew, but not as quickly as demand forecasts might have suggested. In 1942, the War Production Board limited the utilities planned expansion of new power generation facilities to only 5,500 MW and diverted otherwise necessary materials to defense industries.12 By war’s end, capacity rose by only 18%, as shown in Figure 4. Net Generation: The industry scrambled to find alternatives to new or enlarged power plants as a way to meet wartime demand. Investor-owned utilities and federal agencies collaborated to extend transmission lines, create new power pools, and operate facilities at or near maximum capacity for nearly all hours of the day and night. Extension of new transmission lines took place much more quickly than construction of power plants. Today the opposite holds, especially due to permitting rules and public opposition to transmission lines. Remarkably, net power production by utilities during the war years increased by nearly 40%, as illustrated in Figure 5.

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Figure 4 — Installed Generating Capacity, 1941-1945 (Thousand kWh)

Source: Historical Statistics of the United States, Colonial Times to 1970, series S 74-85, page 824.

Figure 5 — Net Annual Production of Power by All Utilities, 1941-1945 (Million kWh)

Source: Historical Statistics of the United States Colonial Times to 1970.

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Other aspects of the US power industry differentiate the response to the unprecedented wartime demand for power during the 1940s from today: For the first hundred years of electrification in the United States, lightly regulated investor-owned monopoly utilities dominated power systems. After the 1990s, states developed competitive wholesale and retail markets, utilities disaggregated, and eventually the federal government stepped in to oversee reliability. The industry is much less cohesive today than it was 80 years ago, while the federal role is more influential than it had been in the past. During wartime, the American public united around causes in support of the effort to defeat the Axis powers, including meeting the defense industry’s demand for electric power. The pressure to rapidly increase available electric power generation today comes in large part from profit-making ventures across the economy, and especially data centers, without a matching expression of public support. While local and regional groups may have attempted to halt new energy infrastructure or large industrial manufacturing facilities in the mid-20th century,13 high-profile opposition to transmission lines, wind and solar farms, generating facilities, and especially data centers is common today. In the midst of unsettling predictions for extraordinary power demand within the next few years, mitigating factors are also at play. As ERCOT notes in its filing, the high demand forecast for 2032 includes large loads that have indicated plans to connect to transmission lines. It is not expected that all of these facilities will be built and operational by 2032. Indeed, following legislation passed in Texas in 2025, ERCOT recently adopted rules to weed out purely speculative projects from more serious investment plans.14 Many large loads are already installing on-site generation and backup storage batteries, indicating that they may not require power from the grid at all times, and, more importantly, may be able to switch to their own electricity/batteries at peak hours so as to offset the need for generation capacity buildout. With on-site generation, these large loads may also offer backup facilities to the grid for brief outages and become effective sources of demand response, lowering anticipated peaks. The questions arise: who will manage the power flow between behind-the meter generation on large load sites and grids, and through what regulatory or market mechanisms? New techniques and technologies for optimizing grid operations may further reduce today’s projected need for more high-capacity transmission and new grid-scale generation. For example, with access to AI and faster and more powerful computers, engineers may develop algorithms to improve the efficiency and cost of operating power systems, increasing the overall capacity of existing infrastructure.15 145

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Similarly, new technologies for the wires inside of transmission lines reduce energy loss as power moves from generators to users thereby increasing capacity. Called reconductoring, replacing old wires with new materials may mitigate the need for new power lines. Additionally, techniques that allow small segments of power networks to isolate from the larger system when something elsewhere goes wrong will aid in addressing stability issues, lessening the requirement for added reserve capacity presented by hyperscale data centers.

Conclusion Lessons from World War II underscore the importance of taking forecasts with a grain of salt. Prewar forecasts failed to align with actual wartime demand both in terms of scale and in terms of timing. A nimble and collaborative industry was capable of meeting large jumps in demand through multiple approaches, including more generating capacity and more transmission, but also through innovation in operations and introduction of new technologies. Importantly, the power industry joined other economic sectors in an all-out commitment to support the nation’s war effort. Utilities shifted investments from generation to transmission, formed power pools, and developed new techniques for meeting demand in centers of defense production. The types of innovation introduced during this period of unprecedented demand, much of which was not anticipated or well-understood at the time, provided valuable technologies to support another electrification boom in the 1950s. This quick trip back in time to compare pre-World War II power demand forecasts with contemporary and anticipated electricity needs leaves out several considerations, including who will bear the cost of added generation and transmission capacity to bring new large loads onto the grid, whether new large loads will upset grid stability and reliability, and what knock-on effects grid expansions and large load additions will have on local and regional communities. With these questions in mind, there are likely additional parallels and contextual insights to be gained from a deeper investigation of past forecasts for unprecedented increases in demand and contemporary anxiety about electrification in the near future.

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Notes 1

https://interchange.puc.texas.gov/Documents/58777_38_1622647.PDF Long-Term Reliability Assessment, North American Electric Reliability Corporation (Washington, DC, January 2026), https://www.nerc.com/globalassets/our-work/assessments/nerc_ltra_2025.pdf. 3 “Today in Energy: In-Brief Analysis,” U.S. Energy Information Agency, May 13, 2025, https://www.eia.gov/todayinenergy/detail.php?id=65264. Accessed June 2, 2026. Ning Lin et al., ERCOT West Texas Load Study: Estimate the Electric Load Impacts of Oil and Gas Related Activities, Bureau of Economic Geology, University of Austin at Texas (Austin, TX, 2022), https://www.ercot.com/files/docs/2022/06/10/ERCOT_West_Texas_Load_Study_Report.pdf. 4 Trieu Mai et al., "Historical and Modern Large Loads: Characteristics, Context, and Industry Actions to Meet Grid and Customer Needs," A White Paper from the Energy Systems Integration Group (March 2026), https://www.esig.energy/reports-briefs/historical-and-modern-large-loads/. 5 Julie Cohn, The Grid: Biography of an American Technology (Cambridge, MA: MIT Press, 2017). 6 "Report of the Committee on Generation and Distribution of Electric Power," Proceedings of the Fiftieth Annual Convention of the National Association of Railroad and Utilities Commissioners, held at New Orleans, Louisiana, November 15-18, 1938, Roosevelt Hotel. (1938): 642. 7 “Confidential Memorandum on Shortages of Electric Generating Capacity for War-Time Needs,” July 1, 1938, Box 2, Tray 72, George W. Norris Papers (Manuscript Division, Library of Congress). 8 David Dietz, "The Future is Electric: Domestic Use Key to Wider Fields," The Cleveland Press (Cleveland, Ohio), April 11 1938. "Report of the Committee on Generation and Distribution of Electric Power." 9 Between 1942 and 1945, the federal government implemented year-round Daylight Savings Time, called “War Time.” 10 Electric Power Requirements and Supply in the United States – War Impact on Electric Utility Industry, 194045, 2 (Washington, DC: Federal Power Commission, 1945). 11 Wellerstein, "Manhattan Project," Encyclopedia of the History of Science, updated October, 2019, accessed June 2, 2026. The Manhattan Project used an estimated 1% of the nation’s power production during 1943. 12 The utilities met this limit with the addition of only 5,100 MW of new generating capacity between 1942 and 1945. Historical Statistics of the United States, Colonial Times to 1970, Bicentiennial Edition, (Washington: US Government Printing Office, 1975). 13 Michael J. Mcdonald and John Muldowny, TVA and the Dispossessed: The Resettlement of Population in the Norris Dam Area (Knoxville, TN: University of Tennessee Press, 1982). 14 Texas Senate Bill 6, “Relating to the planning for, interconnection and operation of, and costs related to providing service for certain electrical loads and to the generation of electric power by a water supply or sewer service corporation,” signed June 20, 2025, https://legiscan.com/TX/bill/SB6/2025; Shelby Webb, "Texas advances major grid rules for data centers," EE News by Politico (June 3 2026), https://www.eenews.net/articles/texas-advances-major-grid-rules-for-data-centers/. 15 Notably, the utility industry tends to be quite conservative and slow to adopt new technologies of this type, thus the potential for improved efficiency may not coincide with the addition of hyperscale data centers and other large loads. 2

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Becoming Standard: Grid-Forming Inverters on All Sides of the Meter Julie A. Cohn Nonresident Scholar

Introduction Since 2022, the Universal Interoperability for Grid-forming Inverters (UNIFI) Consortium has focused on the challenge of integrating new power generation technologies into the electric power grid. For more than a century spinning turbines – powered by burning hydrocarbons, falling water, and nuclear reactors – have dominated the US interconnected power systems (colloquially, “the grid”). The behavior of the alternating current electricity produced by these devices provides signals that power system experts use to measure and control grids. Battery energy storage systems (BESS), solar photovoltaics (PV), and wind turbines, however, connect to the grid via inverters – electronic apparatus that can be programmed to respond to the physical signals of an alternating current network and adjust the flow of electricity accordingly. For more than twenty years, the programming of inverters assumed that spinning turbines and their associated physics would dominate the grid, and thus it was necessary for the inverter-based resources to “follow” the signals from the grid. The UNIFI team responded to a request for proposals from the U.S. Department of Energy (DOE)1 seeking to better understand what to do should inverter-based resources reach a critical mass on the grid that could result in instability.2 In addition, DOE wanted to clarify whether multiple grid-forming inverters – that is, inverters programmed to exert signals to the grid – from multiple vendors, and connecting multiple types of resources, could work and play well with each other as well as with the traditional spinning turbines. The ultimate goal of the UNIFI initiative was to reach consensus on how to ensure that the grid would remain as stable and reliable as it has been, if not more so, while the percent of electricity generated by inverter-based resources (IBRs) increases rapidly.

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UNIFI is now reaching its fifth year and the question before the consortium is whether their work has adequately developed a standardized approach to integrating grid-forming IBRs into the grid. There is also the question of moving beyond storage and generation technologies to power-electronic-based loads and power flow controllers. Other types of resources, especially AI data centers, are scaling up rapidly and also connect to power systems via inverters. Data centers offer new behavior patterns that differ significantly from the historical aggregations of generators and power users that comprise interconnected systems: 1. Very large loads with fluctuating demand – when data centers begin and end processing AI queries, they present very sudden and large load changes to the grid. These sudden changes, if unmoderated, can destabilize power systems, potentially leading to a cascading failure. 2. Isolated generation, back-up generation, and energy storage – data centers rely on constant and reliable access to enormous quantities of electricity in order to operate effectively. Many installations incorporate stand-alone power generation and energy storage for off-grid operation and back-up for planned and unexpected system outages. Even if operating entirely islanded, data centers may link to the grid for backup power. This new infrastructure offers both challenges and opportunities a. Data centers with stand-alone power generation could sell excess electricity to the grid. b. Data centers with back-up generation could take on a significant role in demandside grid management. c. Data centers with back-up energy storage could provide off-take for excess grid electricity as well as on-site stand-alone generation. d. Data centers with any of these facilities could provide ancillary services to the grid that improve reliability and stability. e. Data centers with any of these facilities could quickly island from the grid during disturbances elsewhere, mitigating the response challenges for grid operators. f. On the other hand, data centers that island suddenly could also exacerbate problems for operators working to mitigate disturbances. 3. Pressure on interconnection queues – because data centers represent such large and immediate new power use, they create new challenges for integrating resources of all types into an interconnected system.

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4. Grid-forming inverter (GFM) interfaces – each data center represents multiple inverters participating in grid connection. Whether these are grid-forming or grid-following is an open question with various considerations at stake. If grid-forming, how many, where in the system, and what should they be programmed to do? For UNIFI, this opens up new research challenges, and perhaps opportunities, for fine-tuning the role of grid-forming inverters in the near future. At a recent meeting of the UNIFI consortium, this topic was top of mind, as participants focused on the specifications developed to date for inverterbased generating resources, and the development of standards that could be applied broadly for generation, storage, loads, and other power controllers.

Assessing the Challenge UNIFI’s release of Version 3 of the Specification for Grid-forming Inverters3 in January 2026 has set a new bar for interconnection requirements of these systems. This version will be the base document for the newly formed IEEE 2800.1 Standard4 that solidifies these requirements. Just as UNIFI has updated specifications and is pursuing paths for standards, this new challenge presents itself to the grid. Until recently, the biggest threat posed by inverter-based resources has been the potential loss of generation when a grid disturbance triggers a source, such as a solar plant, to disconnect.5 This happens through programming designed to protect the generating source from grid disturbances. If too much generation drops off the grid at once, the grid will become unstable, tending toward an outage. The specifications developed by UNIFI for grid-forming inverters address this problem by giving certain inverter-based resources the ability to act quickly and ride through a disturbance. This means that a solar plant, for example, might receive a signal indicating a problem elsewhere on the system, but the solar plant will not disconnect; instead, it will continue to provide power to the grid while the problem is resolved. Now very large loads, and data centers in particular, are posing a similar threat to the grid. At ERCOT’s April 2026 Board of Directors meeting, Jeff Billo, Vice President, Interconnection and Grid Analysis identified three major risks posed by the operating methods of hyperscale data centers:6 Ride-Through: Sensitive computer equipment trips offline during normal grid events, leading to grid imbalance and instability. Oscillations: Certain data centers’ processes can oscillate in a way that damages grid equipment. Modeling: Dynamic models for large loads have proven to be inaccurate and thus are inadequate for studying their grid impacts. 151

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Examples of the ride-through problem occurred in Texas in 2024 and Virginia in 2025.7 Voltage-sensitive large loads, which include both data centers and crypto-mining facilities, responded to the loss of transmission lines, taking approximately 1500 MW off the grid without warning. Large load protection systems operate to prevent damage to equipment when there are voltage changes on the grid, but to date there is no standardized response used by all large loads to afford some predictability. For grid operators, this was an unprecedented sudden drop in load. Similarly, grid operators have witnessed unanticipated oscillations on systems hosting very large data centers.8 As computers in a data center undertake a training job, they go through many cycles of computation, varying demand rapidly and creating sharp changes in frequency, sometimes adding power to the grid, sometimes drawing power, in previously unforeseen patterns.9 The first step in addressing these oscillations is measuring and characterizing them.10 A later step will involve modifying the power electronics between data centers and grids so that operators can more readily anticipate system behavior. Finally, as these two examples indicate, the dynamic behavior of today’s large loads are different in kind from those connecting to the grid in the past. Older models for grid planning and design fail to incorporate a variety of features, from geographic co-location of data centers to voltage and frequency sensitivity, to speed of response to system status. Looking ahead, the role of power electronics will be increasingly important.

A Role for a Consortium “How can we take UNIFI lessons to standardize integration of new technologies and apply them to data centers?” – Benjamin Kroposki, Director of the Power Systems Engineering Center at the National Laboratory of the Rockies, and Organizational Director of UNIFI

The UNIFI consortium, working for five years now to prepare for widespread integration of inverter-based power generation and storage system resources into the existing grid, has expanded its portfolio to consider this new type of inverter-based resource – the hyper-scale data center. For example, perhaps the inverters connecting data centers and their component elements to the grid can be programmed to ride through disturbances when the risk to equipment is low, rather than exacerbating problems by suddenly taking a large load off the grid. Similarly, perhaps these inverters can be programmed to smooth transitions from on to off, and back on again, without introducing sudden load changes to the grid. At the February meeting of the consortium, engineers pushed these ideas to the fore.

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M.A. Awal, Lead Engineer for EPC Power, a developer of power conversion systems for the grid, when describing deployment of his company’s inverters, referred to data centers as an application for these devices. If data centers incorporate on-site generation, BESS, and gridforming inverters, they will appear as a single load to the grid with ride-through and smoothing capabilities. The BESS can emulate the load to the grid when the data center is offline and can compensate for sudden stops and starts when the data center is online, presenting a more predictable load to the operator. Hussam Alatrash, power conversion engineer with Heron Power, another power electronics developer, also proposed an architecture to use batteries with data centers to maintain stability. Ashwin Venkataramanan, Specialist at Eaton Research Labs, part of Eaton’s power management company, proposed additional future architectures for linking hyperscale data centers to the grid. These presentations raised a myriad of technical and practical questions among the UNIFI meeting participants, indicating research and modeling opportunities ahead for the consortium. This presents an interesting marriage of two technology challenges: standardization and pivoting. In the first case, the consortium is pursuing standards for grid-forming inverters to ensure that the millions of devices, soon-to-be-connected to the grid, from dozens of manufacturers, will cooperate technologically. The standards primarily address inverterbased generation and storage resources. The core idea is to allow design-agnostic interoperability while preserving grid stability. There is a long history of grid engineers designing technical solutions, testing them on the grid, modifying them to improve successful operations, creating informal and voluntary standards, and eventually formalizing standards that grid operators impose on all interconnected components.11 The current UNIFI effort follows in this path, but on a much shorter schedule than was often typical in the past. The pressure to standardize comes from the rapid penetration of renewables and batteries over the past two dozen years, and the emergence of real problems as these components reach a tipping point.12 Pivoting to address a new technical challenge by leaning on solutions to a different problem, likewise, has historical precedent. In a recent oral history project, several power systems engineers described starting their careers with a focus on one type of problem, then expanding to apply their insights and innovations to a different problem, for example from radar tracking to grid monitoring, from motor drives to microgrids, and from frequency analysis to locating a grid disturbance.13 In this case, consortium members again face the press of time.

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Superscale data centers already pose grid stability problems, while UNIFI’s techniques for integrating multiple grid-forming inverters have not yet been tested at scale. Only now are consortium members devising modifications that will successfully mitigate the ride-through and oscillation issues.

Policy Matters The policy implications of these two technology challenges operate on different levels. Grid operators are already weighing and implementing interconnection requirements for gridforming inverters linked to solar, wind, and BESS installations. ERCOT is in the lead, with recently approved policies pending before the Public Utility Commission of Texas.14 While owners of existing facilities balked at an earlier approach proposed by ERCOT,15 the Technical Advisory Committee16 – comprised of consumers, cooperatives, independent generators, independent power marketers, independent retail electric providers, investorowned utilities, and municipal power companies – unanimously supported policies adopted by the board in 2025.17 ERCOT additionally introduced an incentive program for compliance by existing facilities.18 At the national level, both the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) have grid-forming inverters high on their agendas.19 In 2023, FERC issued Order No. 901, calling for reliability standards related to inverter-based resources and approved NERC’s proposed standards in July 2025.20 The standard requires owners of inverter-based generation to ensure their facilities have ride-through capabilities.21 For a future grid replete with IBRs, grid operators across the country will have to resolve their interconnection rules, likely on a case-by-case basis. But the specifications and putative standards developed by UNIFI will provide a basis for formulating those policies. The second challenge – how to mitigate the operating practices of very large loads that currently threaten grid stability, represents a different policy concern. These types of entities, historically, have been grid customers. To date, grid operators have developed programs for demand management that allow loads to respond to peaks and other stressors on the grid. But the opportunity to manage both the demand and the potential generation and auxiliary services offered by large loads is new. Grid operators will be bringing new stakeholders to the table to thrash out the policies that offer both the control needed on the operations side to ensure stability and the flexibility needed on the customer side to assure access to reliable electricity to keep the companies in business.

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Already municipalities, state governments, and even members of Congress are taking up legislation to block, limit, and promote data centers, with great regional variety across the country. It is time for these policymakers to learn about the stability challenge represented by hyperscale data centers and also to study avenues for making new data centers partners in stable grid operations.

Notes 1

DOE CMEI Website, https://www.energy.gov/cmei/systems/unifi-consortium UNIFI Consortium, https://unificonsortium.org/. 3 “UNIFI Specifications for Grid-forming Inverter-based Resources Version 3,” UNIFI-2026-2-1, January 30, 2026, https://docs.nlr.gov/docs/fy26osti/98381.pdf 4 “Recommended Practice for Functional Capabilities and Performance of Grid Forming Equipment in InverterBased Resources (IBRs) / Converter-Based Resources (CBRs),” IEEE Standards Association. https://standards.ieee.org/ieee/2800.1/12387/ 5 Odessa Disturbance: Texas Events: May 9, 2021 and June 26, 2021; Joint NERC and Texas RE Staff Report, North American Electric Reliability Corporation (Atlanta, GA, September 2021), https://www.nerc.com/pa/rrm/ea/Documents/Odessa_Disturbance_Report.pdf. 6 Jeff Billo, “Item 9: Interconnection and Grid Analysis Update,” Presented to the ERCOT Board of Directors Meeting, Austin, Texas, April 20-21, 2026, https://www.ercot.com/files/docs/2026/04/13/9-Interconnectionand-Grid-Analysis-Update.pdf. Slide 5. 7 https://www.nerc.com/globalassets/who-we-are/standing-committees/rstc/whitepaper-characteristics-andrisks-of-emerging-large-loads.pdf. https://www.nerc.com/globalassets/our-work/reports/eventreports/incident_review_large_load_loss.pdf. 8 Chetan Mishra et al., "Understanding the inception of 14.7 Hz oscillations emerging from a data center," Sustainable Energy, Grids and Networks 43 (2025/09/01/ 2025), https://doi.org/https://doi.org/10.1016/j.segan.2025.101735, https://www.sciencedirect.com/science/article/pii/S2352467725001171. 9 Michael Skurta, “Sub-synchronous Oscilation: A Starter Guide for the AI Data Center Era,” Applied Power Technologies, Inc., April 13, 2026, https://apt4power.com/sub-synchronous-oscillation-a-starter-guide-for-theai-data-center-era/. 10 Sandra Jenkins, “Monitoring Oscillations from Large Data Centers,” Office of Electricity, May 28, 2026, https://www.energy.gov/oe/articles/monitoring-oscillations-large-data-centers. 11 Julie Cohn, The Grid: Biography of an American Technology (Cambridge, MA: MIT Press, 2017). 12 Julie Cohn, "Approaching a Tipping Point for the Electric Grid" (Houston: Rice University's Baker Institute for Public Policy, November 20, 2023), https://doi.org/10.25613/rg62-1v68. 13 Algorithms and Power Systems Architecture Project, https://sites.google.com/view/power-systemshistory/home. 14 ERCOT Board of Directors Meeting Agenda, June 1-2, 2026. https://www.ercot.com/files/docs/2026/05/22/0-June-1-2-2026-Board-of-Directors-Agenda.pdf. Policies approved at this meeting will be on the agenda for the Public Utility Commission of Texas later in the month. 2

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Jason Plautz, "How a grid rule change could derail Texas renewables," Energywire (August 4 2023), https://www.eenews.net/articles/how-a-grid-rule-change-could-derail-texas-renewables/. 16 ERCOT Technical Advisory Committee, https://www.ercot.com/committees/tac. . 17 Carlos Matar, "ERCOT Aprroves AGS Requirements (GFM) for Inverter-Based Energy Storage Resources," Electric Power Engineers (October 24 2025), https://epeconsulting.com/epe-intelligence/news/ercot-approvesags-requirements-gfm-for-inverter-based-energy-storage-resources-esrs. 18 Farid Ishak, "ERCOT Introduces Advanced Grid Support (AGS) Incentive Program for IBRs," Electric Power Engineers (May 15 2026), https://epeconsulting.com/epe-intelligence/news/ercot-introduces-advanced-gridsupport-ags-incentive-program-for-ibrs. 19 https://www.nerc.com/globalassets/our-work/white-papers/white_paper_gfm_functional_specification.pdf. https://www.nerc.com/globalassets/standards/projects/2025-05/formal-posting-1/project-2025-05-technicalrationale_041626.pdf. https://www.ferc.gov/news-events/news/ferc-approves-grid-reliability-standardsapplicable-inverter-based-generators. 20 “Order No. 901: Final Rule; Reliability Standards to Address Inverter-Based Resources under RM22-12,” Federal Energy Regulatory Commission eLibrary, https://elibrary.ferc.gov/eLibrary/filelist? accession_number=20231019-3157. “FERC Approves Grid Reliability Standards Applicable to Inverter-Based Generators,” https://www.ferc.gov/news-events/news/ferc-approves-grid-reliability-standards-applicableinverter-based-generators. 21 “PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources,” North American Electric Reliability Corporation, https://www.nerc.com/globalassets/standards/approvedstandards/prc/prc-029-1.pdf.

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ELECTRICITY MARKETS AND POLICY

Competitive Retail Electricity Markets and Consumer Switching in Texas Tilsa Oré Mónago Fellow in Energy and Market Design

Introduction Retail-choice in electricity is a feature of the Texas market. In competitive areas, customers can compare offers from retail electric providers. Retail choice is not statewide; about 15% of consumers are served by municipal and cooperative utilities that lie outside the competitive model. In principle, competitive pressure should push retail prices toward their marginal (wholesale) cost, which is what Hartley et al. (2019)1 find. It also helps explain why the Texas residential price is below average in the U.S. (Figure 1). However, since Winter Storm Uri in 2021, several factors—such as fuel price volatility, winter-storm reforms and associated costs, growing transmission and reliability needs, and higher retail risk premiums—have pushed prices up. Between December 2020 and December 2025, the Texas average residential price rose 37%, with an 8% increase in 2025 alone.2,3

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Under retail competition, retailers bear wholesale price-volatility risk while selling to most customers under fixed-rate contracts—a financial strain that can prove damaging when margins are thin. After Winter Storm Uri, twelve small retailers left the market, either acquired or bankrupted. Some entry and exit is normal in competitive markets, and Texas shows exactly that: between 2021 and 2024, an average of five retail brands entered and four exited each year. By the end of 2024 there were 56 residential retail brands belonging to 43 parent companies, down from 60 and 55 in 2020.4 Table 1 lists the parent companies that have multiple retail brands.

Table 1 — Parent Companies With Many Retail Power Provider Brands (At End of 2024) Parent Company

Retail Brand

NRG Energy, Inc.

Green Mountain Energy Co. Direct Energy Services Reliant Energy Retail Services

US Retailers, LLC Stream SPE, LTD XOOM Energy Texas, LLC

Vistra Energy

TriEagle Energy, LP Ambit Energy Holdings, LLC

TXU Energy Retail Co, LLC Value Based Brands, LLC

Just Energy Group, Inc.

Just Energy Hudson Energy Services Tara Energy, LLC

Smart Prepaid Electric Amigo Energy

Frontier Utilities, LLC

Gexa Energy, LP

NextEra Energy, Inc.

Source: PUC-TX, https://www.puc.texas.gov/industry/electric/directories/rep/alpha_rep/

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Figure 1 — Average Residential Electricity Price by State (Dec 2025)

Source: U.S. Energy Information Administration, Form 861. Note: Average residential price is proxied by the ratio of residential consumer sales revenue to total sales.

Market concentration and retail pricing Although more than 40 players may suggest healthy competition, market concentration matters, too. Brown et al. (2020)5 document a wave of acquisitions through 2019 that raised concentration—measured by the Herfindahl–Hirschman Index (HHI)—into “moderately concentrated” territory under DOJ guidelines. By 2024, two retail brands served 43% of residential consumers; aggregated by parent company, two firms—NRG Energy and Vistra Energy—accounted for 80% of the market (see Figures 2 and 3).6

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Figure 2 — Individual Retailer Market Share (As of Dec 2024)

Source: U.S. Energy Information Administration, EIA-861M monthly data of Retail Power Marketers

It is therefore more meaningful to treat parent companies, rather than brands, as the market players. Monthly HHI based on parent-company shares stayed below 2,400 before 2021. In 2021 it rose sharply above 2,500—reflecting the mass exit of small players and parentcompany consolidation—and has remained above that threshold, indicating a highly concentrated market (see Figure 3).7

Figure 3 — Parent Company Market Share (As of Dec 2024)

Source: U.S. Energy Information Administration, EIA-861M monthly data of Retail Power Marketers

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Concentration alone, however, does not restrain competition; it does so only if dominant players abuse their position in ways that affect prices. Retailers compete on price structure, contract term, renewable content, customer service, and risk allocation. To lower consumers’ search and information costs, the Public Utility Commission of Texas sponsors Power to Choose (PTC), its official, unbiased choice website, where providers list offers for free. Competition shapes how offers are packaged and priced, but it does not remove systemwide cost drivers. Because customers choose their retailer but not their local transmission and distribution utility (TDU), we focus on average retail prices net of TDU charges, deflated to real terms. Figure 4 shows the monthly evolution of real residential prices net of TDU, as a market-share-weighted average. We can observe that prices have risen—sharply in mid-2022 —even as the concentration index slightly edged down. Theory would predict the opposite, since greater concentration raises the risk of market power and higher prices. This suggests the increase reflects not concentration but other factors: wholesale energy costs, hedging strategies, ancillary-service and reliability costs, customer-acquisition costs, and the regulatory changes that followed Winter Storm Uri.

Figure 4 — Real Weighted Net-Of-TDU Price vs. HHI-Parent (2021-2025)

Source: U.S. Energy Information Administration, EIA-861M monthly data of Retail Power Marketers

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A closer look shows that retailers with larger market shares tend to charge more: the median price of top-quartile retailers (by market size) exceeds that of the bottom quartile (Figure 5). This is consistent with Brown et al. (2020)8, who find that firms active in both generation and retail sales—such as those associated with Vistra and NRG—price higher than independent retailers. If economies of scale drove price differences, larger firms should price lower than smaller ones—the opposite of what we observe.

Figure 5 — Real Retail Prices by Market Share Quartile (2024)

Source: U.S. Energy Information Administration, EIA-861M monthly data of Retail Power Marketers

Another reason why prices may differ is due to differentiation features, such as perceived higher quality, reputation or customer loyalty. Yet another explanation is exercise of market power by dominant players, which can be reinforced by consumer inertia and lack of switching behavior. Thus, even though a parent company acquires additional retailers and operates multiple retail brands, competition can remain strong if those brands still face pressure from other offers and from consumers who are willing to leave. The health of the retail market is therefore behavioral as well as structural because it depends not only on ownership counts, but also on whether customers can see credible alternatives and act on them.

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Prices may also differ because of differentiation-perceived quality, reputation, or customer loyalty. Market power remains a possible explanation when higher prices persist alongside consumer inertia (weak or no switching). Even when a parent company operates multiple brands, competition can stay strong if those brands still face pressure from rival offers and from customers willing to leave. Thus, the competitive assessment should link structure to behavior: whether consumers compare plans and switch when better offers are available.

Consumer Switching as Market Discipline Consumers discipline the market when they compare plans, respond to introductory offers, and leave providers whose prices rise after the initial term. In that sense, switching is not a marginal inconvenience; it is one of the central mechanisms that keep a competitive retail market healthy. Introductory offers are priced aggressively because retailers compete for the future value of the customer relationship. Once a customer is enrolled, the provider gains pricing power if that customer is inattentive, dislikes searching, or faces cancellation fees. This is the practical importance of switching costs: even with many offers, competition weakens if customers do not compare, cannot understand the terms, or choose not to switch. A market with many listed offers can still stagnate if consumers rarely switch. Low switching lets retailers segment customers into active shoppers and inactive ones: active shoppers get the best promotional prices, while inactive customers face higher renewal rates or less favorable plans. Higher switching narrows this gap by forcing providers to compete for existing customers, not just new ones. The switching-cost literature offers a useful distinction. Some costs are contractual, such as early-termination fees; others are behavioral or informational, such as the time to compare plans, the fear of choosing badly, or confusing contract terms. Oré Mónago (2018)9 finds that early-termination fees need not deter switching: firms dynamically optimize profits, offering low introductory prices and raising them later. Consumers should weigh the expected savings from a new plan against the cancellation fee and the time left on their contract; when expected savings exceed the cost of switching, changing providers is rational and helps preserve competitive pressure. Texas is a useful case because retail choice is not passive. Residential customers have switched at about 1.6% per month and 19.4% on a rolling 12-month basis. Switching fell markedly by the third quarter of 2022 to around 17% from roughly 22% in 2021. Figure 6 shows that that the slowdown since late 2022 coincides with higher real retail prices net-ofTDU, and the rolling 12-month switching rate is negatively related to those prices. Energy Insights 2026

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Figure 6 — Real Weighted Net-Of-TDU Price vs. Yearly Switching Rate

Source: U.S. Energy Information Administration, EIA-861M monthly data of Retail Power Marketers. Switching rates were calculated based on information of the ERCOT Monthly Operational Overview.

One of the reasons for restrained consumer switching in Texas identified by Hortacsu et al. (2017)10 is precisely consumer inertia. Households rarely search for alternative providers, and when they do, they attach a significant brand advantage to the incumbents (or affiliated retailers) such as TXU energy and Reliant Energy, the former vertically integrated utilities TU Electric and Houston Lighting & Power respectively. As indicated in Figure 5, small retailers not only offer lower prices than larger ones; they also offer a wider range of options. Texan households can capture real savings by shopping and switching, a process that takes under ten minutes and does not interrupt service, which the transmission and distribution utility continues to provide. Residential electricity plans are published on Power to Choose (PTC), the official electric choice website. The site supports competition only if consumers use it actively and read offers carefully. Strengthening competitive pressure therefore requires better consumer use of PTC, alongside clearer disclosures and broader public education about why and when to switch. Such improvements would enhance retail choice even as ownership becomes more concentrated.

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Competitive Retail Electricity Markets and Consumer Switching in Texas

In sum, competitive markets are often imagined simply as many sellers competing fiercely for customers. That view, however, casts consumers as passive and equates competition with the number of firms. If, in turn, policy tends to focus narrowly on firm behavior, it could be misaligned with promoting the intended benefits of competition. In practice, competition is a web of relationships among firms, regulators, and consumers. Consumers’ switching behavior is central to determining appropriate policy interventions regarding how firms behave. Retail electricity competition in Texas should be assessed through both structure and behavior. Ownership concentration warrants monitoring, but the real test is whether customers have understandable alternatives and use them. When consumers compare plans and switch as prices rise, introductory offers become a genuine competitive tool rather than a path to lock-in. Retail choice can discipline providers even in a more concentrated market. If consumers remain inactive, concentration and brand loyalty can translate into higher prices. The market’s health depends not only on the number of brands, but on the continued willingness and ability of Texans to exercise choice.

Notes 1

Hartley, P. R., Medlock, K. B., III, & Jankovska, O. (2019), “Electricity reform and retail pricing in Texas,” Energy Economics, 80, 311–320. https://doi.org/10.1016/j.eneco.2018.12.024. 2 See https://www.ercot.com/files/docs/2025/11/17/ERCOT-Grid-Insights-Retail-Market.pdf 3 The average residential price is proxied by the ratio of total state revenues from residential consumers to state level residential electricity consumption. Sourced from the U.S. Energy Information Administration Form 861. 4 Based on the information from the U.S. Energy Information Administration, Form 861M, monthly series for Texas’ retail power marketers. 5 Brown, D. P., Tsai, C.-H., Woo, C. K., Zarnikau, J., and Zhu, S. (2020), “Residential electricity pricing in Texas’s competitive retail market,” Energy Economics, 92:104953. 6 The HHI is calculated as the sum of squared market shares of all the market players, where a value of 10,000 indicates a total monopoly. According to the Department of Justice Guidelines, an HHI lower than 1500 indicates “no market concentration”, an HHI higher than such level but lower than 2,500 indicates a “moderate market concentration”, and HHI values equal or above 2500 indicate a “high market concentration.” 7 The story can be completely misleading if the HHI over the retailers’ brands’ market shares is used. The HHI index by December 2024 is calculated to around 2600, which indicates a highly concentrated market by the same DOJ guidelines. 8 Brown, D. P., Tsai, C.-H., Woo, C. K., Zarnikau, J., and Zhu, S. (2020), “Rising market concentration in Texas’s retail electricity market,” The Electricity Journal, 33(9):106845. 9 Ore Monago, T. (2018) “Essays on Consumer Inertia,” PhD Thesis, Stony Brook University, Department of Economics, August. 10 Hortacsu, A., Madanizadeh, S. A., and Puller, S. L. (2017), “Power to choose? An analysis of consumer inertia in the residential electricity market,” American Economic Journal: Economic Policy, 9(4):192–226.

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ENERGY AND GEOPOLITICS IN EURASIA

What Lessons Did China and India Learn From the Last Great Global Energy Shock? Gabriel Collins Baker Botts Fellow in Energy and Environmental Regulatory Affairs | CES Lead, Energy and Geopolitics in Eurasia

China learned to pursue insulation through self-reliance and electrification; India learned that energy shocks become food and household welfare shocks.

Introduction The last time the world suffered an oil and energy shock as big as what the Iran War and Strait of Hormuz closure have triggered, it was 1973. China’s General Secretary Xi Jinping was a 20-year-old working in rural Shaanxi Province, where he had been sent down to the countryside during the Cultural Revolution. The Cultural Revolution would not end for three more years. Indira Gandhi was the Prime Minister of India, which was experiencing a massive uptick in human wellbeing due to the Green Revolution entering full swing and ending the famines that had repeatedly stalked the country in earlier years. Oil was just starting to meaningfully feed each country’s energy metabolism, with India and China obtaining about 10% of their primary energy from oil in 1973, less than half the share oil occupies today. Most of their primary energy came from biomass and coal. As such, they were very differently situated than Japan, which in 1973 obtained approximately 80% of its total primary energy from oil and gas, virtually all of which was imported. Energy Insights 2026

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Today, both China and India each derive approximately 30% of their primary energy supply from oil and gas, with each commodity exposed to the price impacts of a major global disruption like the one now occurring. India is especially exposed, given that it lacks China’s significant domestic oil and gas production. Both countries are now central cogs in the global energy machine and as such, the essay briefly examines each of their responses to the 1973 Oil Embargo and how steps taken then do (or do not) foreshadow measures they are likely to take in coming years following the Iran War Oil Crisis.

China’s Response to the 1973 Oil Shock: Strive for Self-Sufficiency China brought the massive Daqing Oilfield into production in 1960, followed by the slightly smaller but still enormous Shengli Oilfield in 1964. Oil production defied the chaos of the Cultural Revolution and grew significantly between 1960 and 1973. China became a net exporter of oil by 1965, primarily to Japan, which had heavily funded the development of the Chinese oil industry through oil-backed loans. China’s positive oil balance meant that—unlike European countries, Japan, and the US—for whom the crisis verged on existential in physical and psychological terms, it was positioned to benefit. As an exporter, China reaped a major windfall from the Arab Oil Embargo. As a declassified CIA report from 1975 put it: “The world oil crisis in the fall of 1973 was a turning point for China's petroleum industry. A threefold increase in the world price of oil provided the incentive to market crude on a large scale.”1 Oil production chased prices, increasing by nearly 30% between 1973 and 1974. The area of highest potential risk exposure for China came on the food supply front, where nitrogen fertilizers played a growing role in ensuring the world’s largest population had enough rice and wheat. Here, domestic urea producers using natural gas in Sichuan and coal elsewhere were able to provide nearly ¾ of China’s nitrogen fertilizer needs by the time OPEC launched the 1973 Embargo.2 Given China’s heavy emphasis on domestic coal, its oil self-sufficiency, and its high degree of fertilizer production coverage, the 1973 Embargo and the 1979 Iranian Revolution each provided more upside opportunities than they did downside risks. The relative insulation gave the Party space for information warfare.

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The CCP’s line was perhaps best summed up in the 15 March 1974 issue of Peking Review, which framed the oil crisis as a struggle “against imperialism and hegemonism” by the United States and Soviet Union.3 Party propaganda also extolled the virtues of energy selfreliance, saying that “Guided by Chairman Mao's revolutionary line, the Chinese people have carried out the principle of maintaining independence and keeping the initiative in their own hands and relying on their own efforts.”4 The emphasis on self-reliance still guides PRC energy security thinking today, more than 50 years later.5 As we contemplate China’s trajectory from this point forth, the Iran War energy and commodity shock is likely to drive three core outcomes: (1) Beijing will continue apace in its attempts to continue expanding its Electrostate and the relative insulation that confers from global oil and gas price volatility, (2) China will also continue building out oil storage capacity because despite electrification, about 20% of the country’s total primary energy use and a much larger portion of transportation energy demand is served by oil, and (3) Chinalinked entities are likely to play significant roles in helping finance alternative infrastructure aimed at diminishing the strategic risks posed by key chokepoints such as the Strait of Hormuz.6

India’s Response: Food Security First, Electrification Second “Ensuring energy security for future generations is one of our biggest challenges. We consider it not only a priority but also as a responsibility towards our citizens.” — Prime Minister Narendra Modi, 18 June 20257

China has gotten a lot of the attention in the past 25 years, but India’s energy demand growth has been equally remarkable. A country that used less energy than Germany in 2000 now uses as much as Germany, Belgium, France, Italy, Spain, and the UK combined.8 Compared to others in its region, India uses basically as much energy as all of its South and Southeast Asian neighbors combined.9 Despite this expansion, it is still growing, with a per capital primary energy usage a bit less than ¼ that of China. For this emerging energy titan, fossil fuels remain foundational, led by coal at about 52% of primary energy in 2025 and oil at 24%. Biomass checks in at about 11% and other sources trail thereafter. Indeed, one of India’s most underappreciated energy stories has been the shift in fuel mix over the past 125 years from a system dominated by biomass to one dominated by modern energy sources.

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Figure 1 — India Total Primary Energy Use by Source, 1900-2025 (Exajoules)

Sources: India 1900–1947: Great Britain, India Office, Statistical Abstract Relating to British India, 1st–55th numbers (London: HMSO, 1867–1921), continued as India, Department of Commercial Intelligence and Statistics, Statistical Abstract for British India, with Statistics, Where Available, Relating to Certain Indian States (Calcutta and Delhi, 1922–1943); volumes digitised by the Digital South Asia Library, University of Chicago. India 1947–1964: India, Central Statistical Organisation, Statistical Abstract of the Indian Union (New Delhi, 1949– ), with electricity backfilled from Central Electricity Authority, Growth of Electricity Sector in India from 1947 Onwards(New Delhi, annual). India 1965–2024: Central Electricity Authority, All India Electricity Statistics: General Review 2025 (New Delhi: Ministry of Power, 2025), data year 2023–24; India, National Statistics Office, Energy Statistics India 2026, 33rd ed. (New Delhi: Ministry of Statistics and Programme Implementation, 2026); India, Ministry of Coal, "Ministry of Coal's Year End Review–2025," Press Information Bureau release PRID 2213723, 12 January 2026; U.S. Energy Information Administration, Country Analysis Brief: India (Washington, DC: U.S. Department of Energy, 6 February 2025); and Ember, India Electricity Data Explorer and India Electricity Data (State-Level) (Ember Energy Research CIC), used under CC-BY-4.0. Sectoral and institutional framing follows B. R. Tomlinson, The Economy of Modern India: From 1860 to the TwentyFirst Century, 2nd ed., New Cambridge History of India III.3 (Cambridge: Cambridge University Press, 2013), and Amiya Kumar Bagchi, Private Investment in India, 1900–1939, Cambridge South Asian Studies 10 (Cambridge: Cambridge University Press, 1972). Note: Indian figures are reported on an April–March fiscal year and are not calendarised. Coal production for FY 2024-25 is 1,047.52 Mt, up 4.98% on 997.83 Mt in FY 2023-24. The CEA General Reviewpublishes one year in arrears. Ember's state-level series begins in 2019 and is not used for earlier years.

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The shift matters greatly for human betterment. It matters for pollution given coal’s present centrality. And it matters for Indian energy security. Energy shocks of the 1970s that seared consumers and policymakers across the OECD world registered differently within India. At that point in time, it was much less about cars and much more about food. Many Indian homes still cooked and heated with biomass, but the agricultural sector was the first to become coupled to global oil and gas geopolitics and the price volatility that followed closely behind. In the 1960s, India was viewed as being on an unchangeable road toward famine.10 Yet by the early 1970s, the Green Revolution was transforming the country’s staple grain production and prospects for feeding its burgeoning population. Fertilizer was one of the most important growth-driving inputs, especially for wheat and rice, with fertilizer use rising from 100,000 tonnes in the 1950-51 crop year to 3.2 million tonnes in the 1973-1974 crop year.11

Figure 2 — Urea Subsidy Share of India Federal Budget vs. Oil Price, 1960-2025

Source: PIB/Department of Fertilizers press releases and annual reports; IEEFA, LNG in Indian Fertiliser Sector; ICAR-IARI Policy Brief 2025; Ansari & Sheereen, Saudi Journal of Economics and Finance; CDS Trivandrum Working Paper 506-AJIL; CAG audit reports on fertilizer subsidy; IIM-A Sharma 2009; Fertiliser Association of India annual reviews; and Energy Institute, Statistical Review of World Energy. Data compiled with assistance of Anthropic’s Claude Opus 4.8 and Fable 5 models.

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During that time, problems within India’s domestic fertilizer sector led to increasing reliance on imports. Between growth in nitrogen fertilizer inputs and the explosive spike in crude oil prices during the 1973 Arab Oil Embargo (which increased the cost of naphtha feedstock used by fertilizer plants), the stage was set for a fertilizer crisis. Farmers applied less fertilizer in 1974, grain output suffered, and hunger gripped India.12 In response, the Indian government began subsidizing urea fertilizer prices in 1977. Since that time, major global oil price spikes—which tend to drag the entire commodity complex up with them—have driven major increases in the Indian government’s urea fertilizer subsidy burden. For instance, the 2008 oil price spike caused urea subsidy outlays to more than 8% of the entire Indian federal budget that year and nearly 4% in 2022 when the Russian fullscale invasion of Ukraine drove oil prices up. Fast forward to 2026, and urea scarcity and price spikes—this time driven by the Strait of Hormuz closure—are once again a serious problem for India’s farmers. Energy security and food security are once again closely intertwined.13 For perspective, if India spent 6% of its budget on urea subsidies, this would be approximately equivalent to roughly twice the U.S. Department of Energy’s enacted budget in Fiscal Year 2025—in short, a substantial amount of money.14 The ongoing energy shock also found a second pathway into Indian kitchens: liquefied petroleum gas. As shipments of LPG through the Strait of Hormuz dwindled in early March 2026, Indian consumers were one of the first groups impacted. LPG is important as an industrial fuel, but of particular political salience, is a vital cooking fuel, as it displaces smoky biomass that was a major driver of respiratory disease. Attention to the LPG issue rose to the highest levels very rapidly.15 The disruptions from today’s crisis creates four areas worth watching in India’s energy decision-making in the coming year: (1) the country is likely to deepen its use of coal as a secure source of electricity, (2) it will likely accelerate the expansion of crude oil and products storage, (3) it will likely encourage greater electrification in areas such as cooking so as to displace imported LNG with more secure domestic coal and renewables, and (4) it will likely consider new investments in domestic, coal-based nitrogen fertilizer production16 This will have meaningful electricity demand impacts because depending on usage patterns, every million homes that adopt induction cooking in the place of LPG could potentially add 2 gigawatts of load, with breakfast and dinner coinciding with lower solar power output.17

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Conclusion Even before the Iran War, 2026 was poised to test the resilience of global energy systems. The conflict has now pulled the system tight and is accelerating energy securitization efforts, particularly in the large consumer countries that have the resource bases, incentives, and fiscal plus technological firepower to try and reshape the system to their relative benefit. China will work to deepen its insulation from global events while maximizing the outside world’s relative dependence on Chinese manufactured goods, including non-fossil energy equipment. India will emphasize food security, household wellbeing, and insulation through electrification. Both countries will lean on coal to accomplish these objectives, and their actions will shape global energy markets far beyond Asia.

Notes 1

Central Intelligence Agency, China Builds Pipelines to Boost Petroleum Exports, Intelligence Report ER IR 7518, June 1975, CIA Freedom of Information Act Electronic Reading Room, https://www.cia.gov/readingroom/docs/CIA-RDP86T00608R000500200019-6.pdf. 2 Food and Agriculture Organization of the United Nations. FAOSTAT: Fertilizers by Nutrient. Rome: FAO, 2026. Accessed June 2, 2026. https://www.fao.org/faostat/en/#data/RFN, Ma, Xinhua. (2017). Natural gas and energy revolution: A case study of Sichuan–Chongqing gas province. Natural Gas Industry B. 4. 10.1016/j.ngib.2017.07.014 3 Chang, Chien. 1974. "Behind the So-Called 'Energy Crisis'." Peking Review 17, no. 11 (March 15, 1974): 5-7. https://massline.org/PekingReview/PR1974/PR1974-11.pdf. 4 Ibid 5 Gabriel Collins, "Energy as a Strategic Space for China: Words and Actions Point to a Competitive Future," Mapping China's Strategic Space, National Bureau of Asian Research (NBR), February 28, 2024, https://strategicspace.nbr.org/energy-as-a-strategic-space-for-china-words-and-actions-point-to-acompetitive-future/. 6 Gabriel Collins, “Wars and Pipelines: How Armed Conflict Has Driven Oil Logistics Diversification,” Rice University’s Baker Institute for Public Policy, April 9, 2026, https://doi.org/10.25613/VSN3-ZT23. 7 Narendra Modi, "Ensuring Energy Security for Our Citizens Is Not Just a Priority, but Also a Responsibility: PM Modi at G7 Summit Session" (speech, G7 Summit Outreach Session, Kananaskis, Canada, June 17, 2025), narendramodi.in, June 18, 2025, https://www.narendramodi.in/ensuring-energy-security-for-our-citizens-is-notjust-a-priority-but-also-a-responsibility-prime-minister-narendra-modi-at-g7-summit-session-594543 8 Energy Institute, Statistical Review of World Energy 2025, 74th ed. (London: Energy Institute, in collaboration with Kearney and KPMG, 2025), https://www.energyinst.org/statistical-review 9 Ibid. 10 Sid Ravinutala, "Redesigning India’s Urea Policy" (Master's thesis, Harvard University, 2016), Page 5, https://www.hks.harvard.edu/sites/default/files/degree%20programs/MPAID/files/Redesigning%20India's%2 0Urea%20Policy_SYPA_Sid%20Ravinutala_2016.pdf.

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Power, Paul F. “The Energy Crisis and Indian Development.” Asian Survey 15, no. 4 (1975): 328–45. https://doi-org.ezproxy.rice.edu/10.2307/2643237. 12 Bernard Weinraub, "India Requesting Food Aid from U.S.," New York Times, September 3, 1974, https://www.nytimes.com/1974/09/03/archives/india-requesting-food-aid-from-us-seeks-emergency-help-butshuns-a.html. 13 Morgan D. Bazilian, Gabriel Collins, and Jahara Matisek, “A Closed Strait of Hormuz Risks a Global Food Security Crisis,” War on the Rocks, April 13, 2026, https://warontherocks.com/a-closed-strait-of-hormuz-risksa-global-food-security-crisis/ 14 Office of Management and Budget, Technical Supplement to the 2026 Budget: Appendix, Budget of the United States Government, Fiscal Year 2026 (Washington, DC: U.S. Government Publishing Office, 2025), https://www.govinfo.gov/content/pkg/BUDGET-2026-APP/pdf/BUDGET-2026-APP-2.pdf 15 Swapnil Joglekar, Utsav Basu, and Deeptiman Tiwary, “India LPG Gas Shortage News Live Updates: ‘Conflict Has Affected Stainless Steel Manufacturing,’ Abhyuday Jindal Says,” Indian Express, updated March 13, 2026, https://indianexpress.com/article/india/india-lpg-gas-shortage-live-updates-iran-israel-restaurants-petrolpumps-10576531/ 16 Gabriel Collins, “Electricity Is the Ultimate Climate Adaptation Commodity,” The Sinews of Civilization, Substack, 1 June 2026. https://gabrielcollins.substack.com/p/electricity-is-the-ultimate-climate 17 Flipkart. “Buy Induction Stoves & Cooktops Online.” Accessed June 10, 2026. https://www.flipkart.com/induction-cooktops/pr?sid=j9e%2Cm38%2C575

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Japan, Korea, and a FiftyYear Education in Energy Vulnerability

Henry Haggard Nonresident Fellow

Introduction Every generation has its own oil shock. Japan and South Korea have now collected four of them and each time, the lesson has been the same: overdependence on a single energy source or trading partner is not an energy policy, it is a wager. February 28, 2026, when U.S. and Israeli strikes on Iran triggered the effective closure of the Strait of Hormuz, was the moment the wager came due again.

Lessons of the Past The 1973 Arab oil embargo hit Japan hard. The economy contracted for the first time since World War II; prices spiraled into what the Japanese called kyōran bukka, “soaring prices.”1 South Korea fared better as its state-directed bureaucracy enabled proactive industrial adjustment that other economies could not match.2 Japan spent the following decade diversifying away from oil-intensive industries, and by 1979’s oil crisis it was measurably better insulated. The lessons drawn after 1973 were structural: reduce petrochemical intensity, expand nuclear capacity, and build strategic reserves. Japan’s oil stockpile program, launched in 1975, would eventually reach one of the highest reserve-toconsumption ratios in the world, a buffer that has proved durable even as the nature of the threats has evolved.3

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Then came Fukushima in 2011. It was not a geopolitical shock; it was an engineering catastrophe that led to the shutdown of all nuclear power generation. Japan responded by pushing for destination-flexibility clauses in its long-term LNG contracts and working to build out regional supply chains, cultivating a deeper, more liquid market that could reroute cargoes in a crisis.4 It was a sophisticated play, but one that depended on the assumption that the market itself would remain accessible. COVID-19 added a different kind of stress test. The pandemic initially collapsed global energy demand; oil use fell by nearly 9 percent in 2020 and electricity consumption in Japan and Korea dropped noticeably, temporarily easing pressure on energy import costs.5 But the reprieve was a trap. When demand rebounded faster than supply in 2021, Japan’s electricity market was dangerously underprepared. JERA had to scramble for emergency spot cargoes as power companies warned of potential blackouts.6 Wholesale electricity prices in Japan hit record highs.7 This highlighted the importance of strategic fuel reserves for an almost entirely import dependent system to maintain supply chain integrity. Korea learned the same lesson differently as its LNG import volumes surged nearly 15 percent in 2021 alone, exposing how quickly import dependence can become a liability when global supply tightens.8 The 2022 Russian invasion of Ukraine exposed the limits of that strategy. When Europe scrambled for LNG, Japan’s monthly import bill nearly quadrupled between April 2021 and August 2022, even though Russian gas was less than 9 percent of its supply.9 Diversification of sources, it turned out, does not protect against diversification of demand. When every buyer panics at once, price is the only adjustment mechanism. South Korea’s utility KEPCO recorded cumulative operating losses exceeding ₩47 trillion between 2021 and early 2024, not from mismanagement, but from the structural trap of import dependence in a price-spiking world.10 Korea responded by accelerating the construction of new LNG import terminals and storage facilities, aiming to bolster its ability to manage supply and demand in an increasingly volatile energy environment.11

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The Current Crisis The current crisis is categorically different. Japan sources roughly 93 percent of its oil imports through the Strait of Hormuz; Korea, around 70.7 percent.12 The head of the IEA has called the 2026 closure “the greatest global energy security challenge in history.”13 What distinguishes this crisis from its predecessors is not merely the scale of the disruption but its mechanism. Within 48 hours of the U.S.-Israeli strikes on February 28, war risk insurance premiums surged fivefold, and major marine insurers terminated coverage or offered replacements at approximately sixty times pre-crisis rates. Lloyd’s Joint War Committee redesignated the entire Arabian Gulf as a conflict zone, and tanker traffic collapsed by more than 80 percent before Iran had physically blocked a single vessel.14 The cost-benefit calculations made by major shipping insurance companies effectively closed the strait before any IRGC intervention. The benchmark freight rate for Very Large Crude Carriers (VLCCs) hit an all-time high, while major container carriers including Maersk, MSC, CMA CGM, and Hapag-Lloyd suspended or rerouted services in parts of the Middle East, with many voyages redirected around the Cape of Good Hope.15 Over 150 tankers anchored outside the strait rather than risk attack. The complication unique to 2026 is that the Houthis, seizing the moment, simultaneously resumed attacks on Red Sea shipping, reversing the fragile recovery since the October 2025 Gaza ceasefire. For the first time in modern history, both major Middle Eastern maritime corridors were simultaneously blocked.16 The immediate response has followed a familiar strategy of drawing down reserves, scrambling for spot cargoes, and leaning on coal. Korea accelerated the restart of nuclear reactors representing 5.7 gigawatts of capacity while Japan lifted restrictions on coal plants.17 These responses work, yet they are not permanent solutions. Japan’s strategic oil reserve, built over five decades, stood at roughly 206 days of consumption at the onset of the crisis, well above the IEA’s 90-day minimum requirement.18 But the gas buffer was far thinner; LNG inventories at the start of March stood at around 4 million tonnes, equivalent to about three weeks of consumption, versus the 90-day oil buffer.19 This asymmetry — deep oil insurance and shallow gas insurance — reflects a structural gap that the pre-crisis policy architecture never adequately addressed. Japan had prepared for an oil shock. The 2026 crisis is at least as much a gas shock as it is an oil shock.

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On the nuclear front, the restart of Unit 6 at the Kashiwazaki-Kariwa Nuclear Power Station in Niigata on February 9, 2026 — TEPCO’s first reactor restart since the Fukushima disaster — proved fortuitously timed. Plant officials estimated that stable operation of Unit 6 could reduce Japan’s LNG imports through Hormuz by approximately 30 percent, displacing 1 to 1.3 million tonnes of LNG annually out of the 4 million tonnes Japan imports from Qatar through the strait.20 Prime Minister Takaichi, who has made nuclear a signature policy priority since taking office in October 2025, stated that Unit 6 combined with expanded coalfired generation could cut Hormuz-transiting LNG imports by roughly 40 percent. As of March 2026, 15 of Japan’s 36 working reactors were in operation with a combined capacity of 37 gigawatts. If all working reactors were brought online, Japan’s annual LNG demand could theoretically fall by a further 12.5 million tonnes.21 The politics of nuclear power remain difficult, the shadow cast by Fukushima remains, but the economics have rarely been more compelling. The coordinated Korea-Japan bilateral response is new. Within two weeks of the Strait’s closure, Korea Gas Corp. and JERA — the world’s two largest LNG buyers — signed a memorandum enabling cargo swaps and joint crisis response, with both governments’ trade ministers at the signing.22 On May 19th, President Lee Jae-myung and Prime Minister Sanae Takaichi met in Lee’s hometown of Andong, marking the first exchange of hometown summit visits between sitting leaders. It was here that they agreed to deepen cooperation on crude oil and petroleum product swaps, strengthen stockpiling coordination, and expand regional supply chain cooperation with Southeast Asia.23, 24 The bilateral context matters, as Japan was South Korea’s third-largest destination for petroleum-product exports in 2025, accounting for 11.3 percent of Korean exports. Together, the two countries represented the world’s second and third largest LNG importers in 2024, accounting for 16.47 percent and 11.43 percent of global LNG imports respectively.23 Their combined market weight, if successfully coordinated, is formidable. At the Andong summit, Lee also announced South Korea’s intention to join Japan’s “POWERR Asia” initiative — the Partnership on Wide Energy and Resources Resilience — backed by $10 billion in Japanese financial support through institutions including the Japan Bank for International Cooperation, aimed at building shared petroleum storage facilities across Southeast Asia.23, 24 Tokyo and Seoul have historically found their worst moments for cooperation to be precisely when it was most needed, when territorial disputes or colonial-era grievances crowded out strategic logic. As Japan’s ambassador to Seoul, Mizushima Koichi, put it during this crisis, “solid Korea-Japan relations are not an option, but a necessity.”25

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South Korea additionally joined Japan, Canada, and five European nations — Britain, France, Germany, Italy, and the Netherlands — in a joint statement condemning Iran’s attacks and calling for freedom of navigation in the Gulf, a diplomatic signal of alignment that would have been harder to imagine even a year earlier.26

Durable Resilience Over the Next Ten Years Over the next ten years, resilience most likely takes the form of nuclear energy. A review conducted by the International Energy Agency supported Korean plans to expand capacity and lead in small modular reactor (SMR) manufacturing.27 The 2024 trilateral U.S.-KoreaJapan agreement on SMR technology provides a ready framework and the Hormuz crisis has given it new urgency. Japan should accelerate its reactor restarts and frame nuclear explicitly as Hormuz-proofing, not just carbon reduction. Nuclear is the one abundant, geographically unconstrained baseload source available to both. If Japan brought all working reactors online, it could displace imports equivalent to more than three times its entire annual Hormuz-transiting LNG volume. Prime Minister Takaichi’s push for new public funding to accelerate SMR construction in Japan and a joint U.S.-Japan project, involving GE Vernova and Hitachi, for up to $40 billion in SMR plants has demonstrated that the political window is widening faster than the industry initially expected. The Hormuz crisis has also accelerated the geoeconomic case for trilateral nuclear cooperation. Nuclear technology exports function like fighter jet sales, anchoring multi-decade partnerships and, by extension, geopolitical alignment. China and Russia are already competing aggressively for overseas contracts, with Rosatom managing twenty VVER reactors currently under construction across multiple countries and China on track to surpass the United States in total nuclear capacity by 2030. The trilateral U.S.-Korea-Japan framework, combining American capital and innovation, Korean manufacturing scale through firms like Doosan Enerbility, and Japanese precision engineering could offer a stable geopolitical and commercial alternative to the Russian and Chinese options. The Hormuz crisis has given that framework new urgency and a clearer political mandate. The renewables picture over the next ten years is more complicated. Japan has been fairly criticized for over-indexing on hydrogen and ammonia at the expense of solar and wind, which are cheaper and faster to deploy.28 A critical concern is that accelerating nuclear restarts risks crowding out renewables through curtailment; each major nuclear restart in Japan has been followed by a measurable reduction in renewable energy generation, with Kyushu a particularly stark example.

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Japan’s Green Transformation plan targets 10 GW of offshore wind by 2030 and 30 to 45 GW by 2040.29 This framing has historically been cast as climate policy, but the Hormuz crisis has reframed it as energy security. Korea faces different constraints with limited land, dense population, and weak grid interconnections with its neighbors. Its own structural challenge is equally revealing—over the past eleven years, South Korea directed approximately ₩141 trillion ($127 billion) to fossil fuels versus just ₩11 trillion ($9.7 billion) for renewables, a 13-fold gap.30 President Lee has called for Korea to move “very quickly” toward renewable energy in response to the crisis.31 Renewables won’t solve a Hormuz crisis in real time, but every gigawatt of domestic generation permanently reduces exposure.32 Finally, the KOGAS-JERA arrangement could serve as the seed for something larger. If Seoul and Tokyo consolidate demand and offer unified long-term purchase commitments to United States LNG exporters, whose capacities could double by 2029, they would stand to gain pricing leverage neither would have alone. A trilateral reserve arrangement, with U.S. crude or LNG pre-positioned in Korean and Japanese facilities with guaranteed emergency purchase rights, would transform a bilateral insurance policy into a multilateral shock absorber. The International Energy Agency has already called joint LNG procurement a “positive step.”33 South Korea’s industrial capacity makes this coordination significant beyond LNG. Korea has positioned itself as a global foundry for nuclear energy; Doosan Enerbility alone has supplied thirty-four major reactor units and 124 steam generators worldwide while investing roughly $596 million to build the world’s first dedicated SMR fabrication facility.34 The same manufacturing depth that underwrites Korea’s nuclear export ambitions is a direct asset in crisis-driven energy coordination.

Conclusion Japan and Korea are U.S. treaty allies whose energy security has been implicitly underwritten by American naval dominance in the Persian Gulf. The 2026 Hormuz crisis demonstrates that this underwriting is conditional; Washington’s commitments coexist with its domestic preoccupations, its Gulf relationships, and its willingness to prosecute a war that created the crisis it is now managing. Neither Tokyo nor Seoul controls those decisions. What they have is each other, and a shared structural vulnerability acute enough to overcome decades of historical friction.

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The question is whether the current crisis produces durable institutional architecture — coordinated procurement, joint reserves, aligned clean energy investment — or whether, once the Strait reopens and prices normalize, the urgency dissipates as it has before. History says: probably the latter. The argument for the former has never been stronger. What makes the current moment different from prior recoveries is that the geoeconomic window is time-limited in a way it was not before. Conservatively valued at $500-740 billion over the next twenty-five years, the global nuclear market is being actively contested. Countries like Ghana, Uzbekistan, Kazakhstan, and Saudi Arabia are making nuclear procurement decisions now. If the institutional architecture built during this crisis — joint reserves, coordinated procurement, aligned SMR investment — does not harden into durable trilateral commitments, the urgency will dissipate as it has before.

Notes 1

Japan Bank for International Cooperation, “Skyrocketing Inflation and Japan’s Economic Slowdown: The Global Oil Crisis and JEXIM’s Efforts”. https://www.jbic.go.jp/en/information/today/today_202307/jtd_202307_column1.html 2 Küçük & Yücekaya, “State Responses to Oil Crisis in Oil-Dependent Developing Countries: South Korea and Turkey after the 1973 Oil Crisis”, International Journal of Asian Studies, Cambridge University Press, November 2023. https://www.cambridge.org/core/journals/international-journal-of-asian-studies/article/state-responsesto-oil-crisis-in-oildependent-developing-countries-south-korea-and-turkey-after-the-1973-oilcrisis/9C63468F9A50B6148097CBE1D722E1AC 3 Loftur Thorarinsson, “A Review of the Evolution of the Japanese Oil Industry, Oil Policy and its Relationship with the Middle East”, Oxford Institute for Energy Studies, February 2018. https://www.oxfordenergy.org/wpcms/wp-content/uploads/2018/02/A-Review-of-the-Evolution-of-theJapanese-Oil-Industry-Oil-Policy-and-its-Relationship-with-the-Middle-East-WPM-76.pdf 4 Neil Theobald / ANGEA, “Japan’s LNG Strategy and Its Role in Asia’s Energy Transition”. https://angeassociation.com/japans-lng-strategy-and-its-role-in-asias-energy-transition/ 5 IEA, “Global Energy Review 2021: Economic Impacts of Covid-19”. https://www.iea.org/reports/global-energyreview-2021/economic-impacts-of-covid-19 6 Reuters / Nippon.com, “Japan’s JERA Buys on LNG Spot Market to Ensure Winter Power Supply”, November 2021. https://www.nippon.com/en/news/reu20211124KBN2I911H/ 7 Aruga, K. et al., “The Impact of Fossil Fuel Market Fluctuations on the Japanese Electricity Market During the COVID-19 Era”, MDPI Energy & Power, May 2025. https://www.mdpi.com/2813-2432/4/2/6 8 S&P Global, “South Korea’s Dec LNG Imports Decline for First Time in 8 Months”. https://www.spglobal.com/energy/en/news-research/latest-news/lng/011722-south-koreas-dec-lng-importsdecline-for-first-time-in-8-months 9 IEEFA, “Japan’s Diversified LNG Procurement Strategy Cannot Fully Shield It from Global Price Spikes”, March 27, 2026. https://ieefa.org/resources/japans-diversified-lng-procurement-strategy-cannot-fully-shield-it-globalprice-spikes 10 The Korea Times, “KEPCO, KOGAS Face Higher Debt Service Costs as Global Energy Supply Tightens”, March 2026. https://www.koreatimes.co.kr/economy/policy/20260310/kepco-kogas-face-higher-debt-service-costsas-global-energy-supply-tightens 11 IEEFA, “South Korea’s LNG Overbuild”. https://ieefa.org/resources/south-koreas-lng-overbuild

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East Asia Forum, “Asia Bears the Brunt of the Hormuz Crisis”, May 14, 2026. https://eastasiaforum.org/2026/05/14/asia-bears-the-brunt-of-the-hormuz-crisis/ 13 New Security Beat, “A New Oil Crisis Stress-Tests the Global Energy Transition”, April 2026. https://www.newsecuritybeat.org/2026/04/a-new-oil-crisis-stress-tests-the-global-energy-transition/ 14 Irregular Warfare Initiative, “The Insurance Weapon: How Commercial Risk Logic Became an Irregular Warfare Tool at Hormuz”, March 24, 2026. https://irregularwarfare.org/articles/insurance-weapon-irregularwarfare-hormuz/ 15 CNBC, “Oil Supertanker Rates Hit All-Time High as Insurers Drop War Risk Protection in the Middle East”, March 3, 2026. https://www.cnbc.com/2026/03/03/middle-east-crisis-iran-us-shipping-oil-tankers-strait-ofhormuz.html 16 Carra Globe, “Strait of Hormuz Closure 2026: What It Means for Your Supply Chain and Shipping Routes”, May 8, 2026. https://carraglobe.com/strait-of-hormuz-closure-2026/ 17 Columbia University SIPA / CGEP, “Asia’s Gas Shock Playbook: Coal, Curtailment, and Competing for LNG”, April 17, 2026. https://www.energypolicy.columbia.edu/asias-gas-shock-playbook-coal-curtailment-andcompeting-for-lng/ 18 Japan Climate Curation, “Vol. 195: No Safe Harbor: The Hormuz Crisis, a ¥2.5 Trillion EV Retreat, and Japan’s Pragmatic Pivot”, March 26, 2026. https://japanclimatecuration.substack.com/p/vol195no-safeharbor-the-hormuz-crisis 19 National Interest, “How the Hormuz Energy Crisis Is Reshaping US, South Korea, and Japan Energy Cooperation”, May 2026. https://nationalinterest.org/blog/energy-world/how-the-hormuz-energy-crisis-isreshaping-us-south-korea-and-japan-energy-cooperation 20 Wake Up Singapore, “Japan Restarts Nuclear Plant After 14 Years, Eyes 30% Cut in LNG Imports as Hormuz Chokes Supplies”, May 4, 2026. https://wakeup.sg/nuclear-restart-reduces-lng-dependence/ 21 IEEFA, “Japan’s Energy Security Response Is Creating a Renewables Blind Spot”, April 27, 2026. https://ieefa.org/resources/japans-energy-security-response-creating-renewables-blind-spot 22 Korea Times, “KOGAS Signs LNG Supply Cooperation Deal with Japan’s JERA”, March 15, 2026. https://www.koreatimes.co.kr/business/companies/20260315/kogas-signs-lng-supply-cooperation-deal-withjapans-jera 23 Korea Herald, “Lee, Takaichi Forge Energy Front as Hormuz Crisis Bears Down”, May 19, 2026. https://www.koreaherald.com/article/10741238 24 Seoul Economic Daily, “Korea, Japan to Share Security Assets, Expand Southeast Asia Stockpile Cooperation”, May 19, 2026. https://en.sedaily.com/politics/2026/05/19/korea-japan-to-share-security-assetsexpand-southeast-asia 25 The Diplomat, “Japan and South Korea’s Energy Hedge”, March 31, 2026. https://thediplomat.com/2026/03/japan-and-south-koreas-energy-hedge/ 26 News on Air (All India Radio), “South Korea to Join Global Efforts to Ensure Safe Navigation in Strait of Hormuz”, March 21, 2026. https://www.newsonair.gov.in/south-korea-to-join-global-efforts-to-ensure-safenavigation-in-strait-of-hormuz 27 IEA, “Korea 2025”, November 2025. https://www.iea.org/reports/korea-2025 28 East Asia Forum, “Why Is Japan Overprioritising Hydrogen and Ammonia over Renewables?”, April 29, 2026. https://eastasiaforum.org/2026/04/29/japans-hydrogen-pivot-is-a-detour-from-real-decarbonisation/; Oil Change International, “Experts React to Japan and South Korea’s Joint Hydrogen and Ammonia Initiative”, November 2023. https://oilchange.org/news/experts-react-to-japan-and-south-koreas-joint-hydrogen-andammonia-initiative/

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ISVD, “The Day the Strait Closes — Japan’s Structural Vulnerability in Energy Security”, March 18, 2026. https://isvd.or.jp/en/columns/hormuz-strait-crisis-japan-energy-security 30 Solutions for Our Climate (SFOC), “Hormuz Blockade Lays Bare Structural Limits of Fossil Fuel Reliance in South Korea, Japan”, March 18, 2026. https://forourclimate.org/newsroom/1190 31 Centre for Research on Energy and Clean Air, “Global Fossil Power Generation Fell After the Hormuz Closure Due to Solar and Wind Growth”, April 15, 2026. https://energyandcleanair.org/fossil-power-fell-in-march-afterhormuz-blockade/ 32 Ember, “The Energy Security Fallout: From Fossil Fuel Fragility to Electric Independence”. https://emberenergy.org/latest-insights/the-energy-security-fall-out-from-fossil-fuel-fragility-to-electric-independence/ 33 IEA, “World Energy Investment 2025: Japan and Korea”. https://www.iea.org/reports/world-energyinvestment-2025/japan-and-korea 34 GWIKS, “Nuclear Geoeconomics: A Trilateral Action Plan for South Korea, Japan, and the US”. https://emmaassets.s3.amazonaws.com/0oueb/cb87e44df58e6005bf73d97ae63e16f9/2026_GWIKS_FPF_Pub_Haggard_C ollins_Final.pdf

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An Energy Tour of the Balkans

Ted Loch-Temzelides CES Lead, Energy Innovation and Policy

Some Political History of the Region The Balkan Peninsula, situated in Southeast Europe, occupies a uniquely strategic and historically complex geographical position. It is bounded in the north by the major waterways of the Danube, Sava, and Kupa rivers, and is defined by its coastlines along the Adriatic and Ionian Seas in the West and the Aegean and Black Seas in the East. The interior terrain is rugged, dominated by the Dinaric Alps, the Pindus, and the Balkan Mountains. Indeed, the very word 'Balkan' is derived from Turkish, meaning 'a chain of wooded mountains.' Today, the region comprises a diverse array of nations, including Albania, Bosnia and Herzegovina, Bulgaria, Croatia, Greece, Montenegro, North Macedonia, Romania, Serbia, Slovenia, and the European portion of Turkey. Historically, this peninsula has served as a dynamic crossroads of civilizations, having been influenced, conquered, and shaped by the Roman, Byzantine, Ottoman, and Austro-Hungarian empires.

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Figure 1 — The Balkans

Source: Encyclopedia Britannica, Balkans | Definition, Map, Countries, & Facts | Britannica

The legacy of these overlapping empires has left a profound imprint on the region's modern political and administrative character. This historical complexity gave rise to terms that are still used in modern geopolitics, such as 'Balkanization,' which describes the fragmentation of a region into smaller, frequently hostile states, and 'Byzantine bureaucracy,' which characterizes overly complex, inflexible, and convoluted administrative systems.

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Consequently, the modern Balkans are often poorer and significantly more bureaucratic than the rest of Europe. The region is marked by fragmented and occasionally hostile relations between neighboring states, an environment that complicates regional cooperation and joint large-scale infrastructure projects. In addition, large segments of the Balkans maintain strong historical, ethnic, economic, and religious ties to Russia. These deeply entrenched ties continue to heavily influence the region's political dynamics and, critically, its modern energy landscape.

General Economic and Energy Facts Economically, the Balkan region presents a picture of stark contrasts and general lag compared to broader European standards. The total population of the designated Balkan countries is around 60 million. Average income in the region trails behind the European Union-27 average.1 Slovenia is the only nation that currently approaches this benchmark. Current GDP in Greece, historically among the highest in the region, still reflects the severe economic scarring from its 2008-2013 financial crisis. Albania, Bosnia and Herzegovina, and the Kosovo region are among the poorest regions in Europe. In terms of domestic energy resources, the Balkans hold significant estimated recoverable hydrocarbon reserves.2 Romania possesses the most robust portfolio of recoverable hydrocarbon reserves. Recently, the offshore energy sector has been experiencing a revival. Following Italy's decision to lift bans on new oil and gas activities, a wave of test drilling targeting potentially massive offshore reserves has commenced. Energy companies are currently aggressively negotiating new exploration licenses in Italian waters. These areas are strategically adjacent to highly promising blocks in Greece's Ionian Sea and south of Crete, drawing international operators like HELLENiQ Energy, ExxonMobil, Chevron, and Energean into the Mediterranean basin. The region has considerable renewable electricity capacity,3 though this remains uneven. Albania represents a unique extreme, generating 99.3% of its net electricity from renewable sources, overwhelmingly driven by its hydropower capacity. Greece leads the region in total renewable infrastructure, primarily from solar and wind generation. Kosovo remains heavily dependent on fossil fuels, with a renewable electricity share of less than 10%, the lowest in the continent. Nuclear electricity generation in the Balkans is concentrated in Romania, Bulgaria, and Slovenia. Nuclear power provides approximately 20% of electricity generation in Romania, about 40% in Bulgaria, and roughly 40% in Slovenia.

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Several other Balkan countries are currently evaluating nuclear energy as part of their longterm energy strategy portfolio. This picture highlights the region's continued need for reliable, baseload energy sources, setting the stage for the strategic development of natural gas.

Recent Developments and US LNG The energy paradigm in the Balkans has undergone a rapid and transformative shift over the past few years, driven primarily by the geopolitical fallout of the Russia-Ukraine war. Prior to this conflict, the region was deeply dependent on Russian pipeline gas. In 2019, the biggest Balkan buyers of Russian natural gas from Gazprom included Croatia (2.82 bcm), Greece (2.41 bcm), Bulgaria (2.39 bcm), and Serbia (2.13 bcm). The outbreak of the war created an urgent mandate to shift away from Russian pipeline gas,4 leading to a massive regional pivot toward liquefied natural gas (LNG), heavily supported by exports from the United States. In this new landscape, Greece and Croatia have quickly established themselves as the early gateways for LNG into Southeast Europe. Greece's Revithoussa LNG Terminal5 in Attica serves as the established primary entry point. With a storage capacity of 225,000 cubic meters, it has recently concluded capacity auctions for 2026-2040 with near-total booking. Complementing Revithoussa is the Alexandroupolis floating storage and regasification unit (FSRU) in Northern Greece. Fully operational since late 2024, this terminal reached a record regasification capacity in early 2026. In the Adriatic, Croatia's Krk island FSRU6 has contributed to regional supply for five years. In early 2026, a major upgrade nearly doubled the terminal's capacity, reaching markets in Croatia, Italy, Bosnia, and Serbia. Beyond Greece and Croatia, other nations in the region are emerging as central energy hubs. Albania is aggressively developing its infrastructure, spearheaded by the planned Vlora LNG terminal. In a landmark April 2026 deal, AKTOR LNG and Albgaz signed a 20-year, six-billiondollar supply agreement to import one billion cubic meters of LNG per year starting in 2030.7 The LNG will be provided by the US company Venture Global. This ambitious project involves an integrated energy hub featuring a natural gas-fired power plant in Vlora and a dedicated pipeline connecting to the Trans Adriatic Pipeline (TAP). Until this infrastructure is completed, initial deliveries will arrive via the Revithoussa terminal and TAP. Montenegro is currently pursuing a feasibility study for an LNG terminal at the Port of Bar.

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The Vertical Corridor The development of the 'Vertical Gas Corridor' (VC) has been hailed as the most critical energy development in the region in recent years.8 This initiative represents a profound strategic realignment of regional infrastructure. A principal component of the corridor is the Trans-Balkan Pipeline, a legacy system originally built to transport Russian gas southward from Ukraine into the Balkans. In a strategic pivot, this pipeline has been repurposed to operate in reverse flow. This allows non-Russian gas, primarily LNG imported through Greece, to move northward through Bulgaria, Romania, and Moldova, into Central and Eastern Europe, and crucially, into Ukraine.

Figure 2 — The Vertical Gas Corridor

Source: Reproduced from Greece Eyes Central Role in Europe’s post-Russia Gas Market - Institute of Energy for South-East Europe

The regulatory foundation for the Vertical Corridor is partially rooted in the European Union's 'Third Energy Package.' This framework was designed to dismantle fragmented national monopolies and create a single, competitive European energy market. A primary mechanism of this package is 'unbundling,' which dictates that companies producing or selling gas cannot simultaneously control the pipelines transporting it. The package mandates the development of interconnectors and reverse-flow capabilities so that gas can move flexibly across Europe, rather than being restricted to rigid east-west routes controlled by single entities.

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The Vertical Corridor initiative perfectly embodies this logic. It facilitates the movement of LNG from Greece, alongside some Azerbaijani gas arriving via the Southern Corridor, through legally separated and strictly regulated networks. Furthermore, the REPowerEU9 initiative launched in 2022 heavily prioritized diversification away from Russian gas, contributing to the expansion of LNG terminals and long-term US contracts. A major strategic advantage of the Vertical Corridor is its connection to Ukraine's massive underground gas storage facilities. This integration would provide critical seasonal flexibility, enabling European nations to build vital reserves prior to winter and enhancing the continent's resilience against supply shocks. Rather than a single pipeline replacing TurkStream, the Vertical Corridor constitutes an expansive, interconnected network, ultimately linking to Italy and Central Europe, as well as Cyprus and Israel in the Eastern Mediterranean. In this integrated system, no single national node will possess the power to veto downstream supply, fundamentally securing the region's energy independence.

Future Plans and Some Challenges Despite the expansion of LNG infrastructure and the strategic promise of the Vertical Corridor, significant regulatory, infrastructure, and political challenges remain. A primary economic obstacle has been 'tariff pancaking.' Historically, the transmission system operators (TSOs) of each individual country along a pipeline route stacked their own transit fees on top of one another, resulting in artificially inflated costs that undermined the competitiveness of non-Russian gas. However, a major breakthrough was achieved recently when participating TSOs from Greece, Bulgaria, Romania, Moldova, and Ukraine agreed to an 'integrated tariff.' Scheduled to take effect in October 2026, this agreement will drop transit tariffs along the Vertical Corridor to a flat €6.5-€7/MWh,10 effectively halving costs and enhancing the competitiveness of US LNG against legacy supplies. Infrastructure bottlenecks also present ongoing challenges. In Bulgaria, a long-standing constraint exists within a 60-kilometer segment between Rupcha and Vetrino. The completion of this segment is critical, as it will unlock additional reverse flow capacity via the Trans-Balkan Pipeline, allowing US LNG to reach Ukraine's storage far more efficiently.11 Concurrently, political resistance and regional market entrenchment continue to preserve the influence of Russian gas. Nations such as Serbia, Hungary, and North Macedonia maintain reliance on gas supply and transit agreements with Gazprom. Serbia, for example, remains the only Western Balkan state deeply tied to Russian gas via TurkStream12 for its base supply, and Belgrade is reportedly close to signing another long-term arrangement. Energy Insights 2026

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By 2027, the EU requires that all gas entering the bloc must be certified as not being of Russian origin. However, long-term contracts and firm capacity bookings on TurkStream via the Turkey-Bulgaria border are likely to continue facilitating Russian flows in the region. Finally, the rapid restructuring of the Balkan energy market raises broader geopolitical and environmental concerns. Although, unlike pipeline supplies, LNG is not tied to a particular producing country, and US LNG is supplied via private contracts, there is some anxiety in the region about trading a historical dependence on Russian energy for a possible overdependence on the United States. Additionally, some nations fear too much operational control is concentrating in Athens. Environmentally, the massive long-term investments in fossil fuel infrastructure create inherent tensions with the EU's strict climate targets. Finally, hanging over all these ambitious plans and developments is the ultimate geopolitical unknown: what will happen to this newly forged infrastructure network if and when Russian gas returns to the European market?

Notes 1

World Economic Outlook (April 2026) - GDP per capita, current prices. Europe – Countries & Regions - IEA. 3 Context: Energy systems, prices, climate and reform commitments in the Western Balkans: Energy Prices and Subsidies in the Western Balkans | OECD 4 ACER report on Russian gas import contracts and diversification - 2026 5 Poseidon MedII LNG BUNKERING PROJECT. 6 About terminal - LNG Hrvatska 7 Greece’s AKTOR LNG USA and Albania’s ALBGAZ in 20-Year Deal for American LNG - The National Herald 8 U.S. Department of Energy Brings Together Vertical Gas Corridor Countries to Strengthen Energy Coordination | Department of Energy 9 REPowerEU 10 Network tariffs | www.acer.europa.eu 11 Study by Energy Community: Unlocking Commercial Attractiveness of the Trans-Balkan Pipeline System - EU NEIGHBOURS east 12 TurkStream 2

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Limits and Consequences of Sanctions on Russian Energy Products Raúl Bajo-Buenestado Nonresident Scholar

Introduction On June 14, images of British commandos descending from a helicopter onto an oil tanker in the English Channel made headlines around the world.1 The vessel, carrying approximately 700,000 barrels of Russian crude oil, was seized while sailing under a Cameroonian flag.2 Just days earlier, the French navy had intercepted another tanker, this one registered in Madagascar, that had recently departed a Russian port carrying oil, marking France's third such operation in 2026.3 Both actions were hailed by national authorities as important victories in the enforcement of sanctions imposed following Russia's invasion of Ukraine. These incidents—and the public celebrations that followed them—were far from isolated. Over the past two years, and particularly since the beginning of 2026, European countries have conducted a growing number of inspections, detentions, and sanctions targeting vessels linked to Russia's so-called "shadow fleet", a global network of tankers and intermediaries that enables Russian energy products to move through international markets despite Western restrictions.4 Such operations have routinely been presented by national governments as major enforcement successes and have publicly been welcomed by Ukrainian authorities as evidence of growing pressure on the Kremlin. As the UK government officially claimed, “starving Putin’s war machine” is a priority.5

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Energy Sanctions: Holding Back the Tide Despite the official celebrations, these operations should not be mistaken for evidence that sanctions have halted the flow of Russian energy products. More than four years after the invasion of Ukraine, and despite the restrictions imposed by Western countries, Russia has consistently found ways to continue selling crude oil and petroleum products on global markets in large quantities— sanctions have just increased costs and logistical complexity of doing so.6 One of the main channels through which Russia has maintained its energy exports is the shadow fleet described above, through which it has been able to send substantial volumes of crude oil directly to countries such as China and India.7 While the detention of individual vessels often generates significant media attention, these operations affect only a small fraction of a network that is estimated to comprise hundreds of tankers operating worldwide.8 The events following the June 14 seizure illustrate this point: in the days that followed, vessel-tracking data showed several tankers altering their routes to avoid the English Channel. For Russia, such adjustments simply imply longer routes (sailing around the northern tip of the British Isles) and higher transportation costs, but they do little to prevent its crude oil from ultimately reaching its intended destinations. Russian energy products do not need to travel directly from a Russian port to their final destination. In some cases, cargoes undergo what are known as ship-to-ship transfers, whereby petroleum products are transferred between vessels in international waters (where law enforcement is weak).9 These operations allow cargoes to arrive at a destination port aboard a non-sanctioned vessel, making sanctions enforcement dependent on authorities' ability to trace the product's origin. This challenge was illustrated by the case of the tanker Maersk Magellan, which was denied entry to a Spanish port after authorities reconstructed a complex chain of transfers: the cargo had previously passed through a vessel sailing under a Cameroonian flag (of Russian origin), and subsequently through another vessel sailing under a Vietnamese flag before being loaded onto the Singapore-flagged Maersk Magellan.10 While authorities were able to document the full chain of transfers in this case, establishing such links is difficult and requires extensive investigative efforts—the Spanish operation (conducted in June 2023) is, in fact, one of the few documented cases of a vessel detained after reconstructing an entire ship-to-ship transfer chain.11

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Sanctions are also systematically bypassed through trade diversion.12 Since 2023, Russia has increasingly redirected crude oil and petroleum product exports toward countries that have not adopted comparable restrictions, such as Turkey and the United Arab Emirates.13 There, Russian crude can be refined before being re-exported to sanctioning states as a product originating from the country where it was transformed; likewise, petroleum products already refined in Russia may be exported to a third country and subsequently re-exported elsewhere.14 Matching this story, two major European energy trading houses ranked among the top-10 buyers of Russian refined petroleum products (an activity that remained permissible after the invasion of Ukraine).15 The importance of this channel is further illustrated by developments in the European diesel market. Prior to the invasion of Ukraine, the EU was heavily dependent on Russian diesel imports.16 Yet despite this dependency, restrictions on Russian diesel did not place upward pressure on diesel prices relative to gasoline. Quite the opposite: following the introduction of sanctions, diesel prices at the Rotterdam hub—the benchmark for European diesel markets—did not rise relative to gasoline prices (a product for which the EU's dependence on Russian imports was considerably smaller) and, in fact, slightly declined.17 At the same time, exports from the EU to Russia's main trading partners increased dramatically (see, for example, the more than 5,500% increase in German exports of cars and automotive parts to Kyrgyzstan, alongside similarly large increases to Kazakhstan, Armenia, Georgia, and Azerbaijan),18 suggesting that trade diversion likely operated in both directions and illustrating the broader reconfiguration of trade routes in global energy markets and beyond. Yet not all Russian energy exports that entered Europe after 2022 did so through sanctions evasion or trade diversion. In several cases, exemptions were deliberately incorporated into the sanctions regime where a complete embargo would have imposed substantial costs on certain EU countries. Bulgaria, for example, continued importing Russian crude oil under a temporary derogation,19 while Hungary and Slovakia have retained access to Russian oil through the Druzhba pipeline (EU restrictions primarily targeted seaborne imports).20 Natural gas provides an even more striking example: although often overlooked, the EU never imposed a comprehensive ban on Russian natural gas, and several member states continued purchasing both Russian pipeline gas and liquefied natural gas (LNG).21 Thus, paradoxically, while European authorities were seizing tankers suspected of carrying Russian oil and petroleum products, large quantities of Russian pipeline natural gas and Russian LNG continued entering European markets through entirely legal channels. 197

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The Hidden Macroeconomics of Sanctions Given these developments, it is perhaps not surprising that the impact of sanctions on global oil markets proved more modest than many initially expected.22 Although oil prices surged immediately following Russia's invasion of Ukraine, much of that increase was subsequently reversed as markets adapted to new trading patterns, as sanctions simply changed where Russian oil was sold. The most salient effect of sanctions was perhaps the segmentation of global crude oil markets, with non-Russian-origin crude existing alongside discounted Russian-origin oil, a distinction reflected in the widening price gap between Urals crude and other benchmark grades—due to a combination of higher transportation costs, greater commercial risk, and the increased bargaining power of major Russian-oil buyers (China and India).23 In practice, this segmentation translated into only a relatively modest decline in Russia's crude oil export revenues. Financial markets tell a similar story. In principle, sanctions that restrict a country's exports (and therefore reduce the inflow of foreign currency), together with an increase in precautionary demand for foreign currency by households and firms during periods of heightened uncertainty, should place downward pressure on the domestic currency.24 Consistent with these expectations, the Russian ruble collapsed in the immediate aftermath of the invasion and the imposition of sanctions, losing roughly half of its value against the U.S. dollar. Yet the collapse was short-lived: within a matter of months, the ruble stabilized and recovered much of its pre-war value.25 In fact, evidence suggests that much of the initial depreciation reflected precautionary behavior surrounding the outbreak of the war rather than a persistent reduction in Russia's capacity to generate export revenues. The implications of these developments extend beyond Russia. Because oil prices are a “fundamental” in macroeconomics—that is, a key determinant of inflation and economic activity—the effectiveness (and limitations) of sanctions have important implications for central banks around the world.26 To the extent that shadow-fleet operations, trade diversion, and other adaptation mechanisms allowed Russian oil to continue reaching global oil markets (albeit in a segmented fashion), they also influenced the trajectory of energy prices in different parts of the world, with differential effects on inflationary pressures, economic activity, and trade outcomes.

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In general, the emergence of trade diversion and other adaptation mechanisms exerted downward pressure on global oil prices, but, due to the sanctions-induced segmentation of oil markets, the effects differed across countries. China, one of the largest purchasers of discounted Russian crude, benefited from lower oil import costs, which reduced production costs, supporting industrial activity. Given China's central role in global supply chains, these effects reverberated elsewhere.27 For the US, as a major oil producer, lower global oil prices reduced revenues in the energy sector, while the EU, as a net oil importer, initially faced the prospect of significantly higher energy costs following the sanctions. At the same time, however, both the US and the EU benefited from cheaper imports of intermediate goods from China, which supported supplydriven growth in the US and helped moderate inflationary pressures in Europe.28 In this sense, some of the mechanisms that weakened the effectiveness of sanctions may also have mitigated part of their macroeconomic cost for Western economies.

The Unintended Microeconomic Consequences Beyond their effects on global trade flows and macroeconomic outcomes, sanctionsevasion mechanisms can reshape competition and industrial dynamics within domestic markets in ways that have received far less attention. Spain's diesel market provides a particularly revealing example. Although Spain possesses significant domestic refining capacity, it remains heavily dependent on imported diesel.29 Prior to the invasion of Ukraine, Russia was one of Spain's most important external suppliers, accounting for roughly 20% of total diesel imports. Following the introduction of sanctions, direct imports from Russia disappeared but, at the same time, the country experienced a remarkable increase in diesel imports from countries that had previously played a marginal (or nonexistent) role as suppliers, such as Turkey, Singapore, and Switzerland, with imports from these countries increasing by nearly 3,000% in 2023.30 This fact, together, with the aforementioned detained the Singapore-flagged Maersk Magellan, naturally raises the question of whether part of the diesel previously imported directly from Russia continued reaching the Spanish market through indirect channels. Similarly to what occurred in crude oil markets, sanctions contributed to a segmentation of international diesel markets, with Russian-origin diesel trading at a substantial discount relative to diesel sold in Northwest European markets.31 199

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If part of the nearly 3,000% increase in diesel imports from countries such as Turkey and Singapore reflected access to lower-cost Russian-origin diesel, some fuel retailers in Spain would have been better positioned than others to benefit from lower wholesale prices. The result was a striking divergence in retail prices driven by differences in fuel procurement: Spanish gas stations with greater flexibility to source fuel from import terminals and storage facilities charged diesel prices that were, on average, approximately 21% lower than those of otherwise comparable stations tied to vertical agreements that required them to purchase fuel from domestic or other European refineries. In this sense, the segmentation of international diesel markets appears to have translated into a segmentation of Spain's domestic retail fuel market. The Spanish case illustrates how sanctions- breaching mechanisms can reshape competition within domestic markets in unintended ways by generating winners and losers among firms operating in the same industry. In this specific case, they did so by creating substantial differences in wholesale procurement costs, placing retailers unable to access lower-cost supply chains at a competitive disadvantage and, potentially, increasing costs for downstream businesses and consumers dependent on higher-cost fuel suppliers. But the implication of this extend beyond market competition: because diesel is an important component of consumer prices,32 these developments may also have contributed to moderating inflationary pressures in Spain, thus connecting the microeconomic consequences of sanctions evasion to the macroeconomic effects discussed above.

Conclusions More than four years after the invasion of Ukraine, the evidence suggests that sanctions, rather than reducing the physical flow of Russian energy products, have simply reshaped (and segmented) global energy markets. The result was a more modest impact on both global oil prices and Russian export revenues than many initially anticipated, alongside important redistribution effects across countries: China appears to have benefited from access to discounted Russian energy, while the effects for the US and European were more nuanced, combining both costs and benefits. At the microeconomic level, the Spanish diesel market illustrates how these developments may also have reshaped competition within domestic industries in unintended ways.

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These consequences (and limitations) of sanctions raise two broader reflections. First, if Russian energy products are already reaching global markets through alternative channels, the eventual removal of sanctions may have a smaller effect on energy prices than is often assumed, beyond the short-run adjustments that would follow. Second, the experience of the past years highlights a fundamental question for policymakers: if sanctions primarily altered trade routes rather than trade volumes, how should their effectiveness be evaluated? Looking back, while some nations can be proud of the dozens of vessels seized, one cannot help but ask whether the ultimate effects of sanctions matched the ambitions with which they were introduced.

Notes 1

The Guardian, 2026. “British armed forces intercept Russian shadow fleet oil tanker in Channel.” https://www.theguardian.com/uk-news/2026/jun/14/british-forces-intercept-russian-shadow-fleet-vesselenglish-channel; BBC, 2026. “Arrest made after seizure of Russian shadow fleet oil tanker.” https://www.bbc.com/news/articles/cevlxg72kyvo; BBC, 2026. “Royal Marines board Russian shadow fleet oil tanker in English Channel.” https://www.bbc.com/news/articles/clyek039l2vo 2 Al-Jazeera. 2026. “UK seizes Russian ‘shadow fleet’ tanker – what that means.” https://www.aljazeera.com/news/2026/6/16/uk-seizes-russian-shadow-fleet-tanker-what-that-means 3 CNN World, 2026. “France seizes another sanctioned tanker carrying Russian oil.” https://edition.cnn.com/2026/06/01/europe/france-russian-tanker-intl; BBC, 2026. “France seized sanctioned Russian oil tanker with UK help, Macron says.” https://www.bbc.com/news/articles/cn8pwgej1gxo 4 Al-Jazeera. 2025. “Russia’s ‘shadow vessels’ using false flags to skirt sanctions, report says.” https://www.aljazeera.com/economy/2025/11/27/russias-shadow-vessels-using-false-flags-to-skirt-sanctionsreport-says 5 UK Governemnt (press release), 2026. “Shadow fleet set to be interdicted in UK waters in latest blow to Russia.” https://www.gov.uk/government/news/shadow-fleet-set-to-be-interdicted-in-uk-waters-in-latest-blowto-russia 6 Downs, E., Fishman, E., Mitrova, T., & Nephew, R., 2025. “How Will New US Sanctions Affect Russia’s Energy Sector?” Blog, Center for Global Energy Policy (Columbia University). 7 Babina, T., Hilgenstock, B., Itskhoki, O., Mironov, M., & Ribakova, E. (2023). Assessing the impact of international sanctions on Russian oil exports. Available at SSRN 4366337. 8 Fernández-Villaverde, J., Li, Y., Xu, L., & Zanetti, F. (2025). “Charting the uncharted: The (un) intended consequences of oil sanctions and dark shipping.” NBER Working Paper 33486. 9 Reuters, 2024. “Ship-to-ship loadings of Russian diesel pick up in northern Aegean.” https://www.reuters.com/business/energy/ship-to-ship-loadings-russian-diesel-pick-up-northern-aegean-202408-13/ 10 Ministerio de Transporte y Mobilidad de España (press release), 2023. “Mitma prohíbe la entrada del buque Maersk Magellan al puerto de Tarragona por transportar hidrocarburos procedentes de un buque ruso.” https://www.transportes.gob.es/ministerio/comunicacion/sala-prensa/vie-10022023-1803; Reuters, 2023. “Danish-operated tanker banned from Spanish ports over oil transfer.” https://www.reuters.com/article/markets/commodities/danish-operated-tanker-banned-from-spanish-portsover-oil-transfer-idUSL8N34V45I/

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Global Trade Review, 2023. “Ship-to-ship-to-ship.” https://www.gtreview.com/magazine/the-fintech-issue2023/ship-to-ship-to-ship/ 12 Kilian, L. & Patel, K., 2023. “Trade diversion has helped ease the impact of the embargo on Russian oil.” Federal Reserve Bank of Dallas blog. https://www.dallasfed.org/research/economics/2023/0221; Morgan, T. C., Syropoulos, C., & Yotov, Y. V. (2023). “Economic sanctions: Evolution, consequences, and challenges.” Journal of Economic Perspectives, 37(1), 3-29. 13 Bloomberg, 2023. “Russia’s Diesel Exports Ban Is Risky for Moscow and World Alike.” https://www.bloomberg.com/news/articles/2023-09-22/russia-s-diesel-exports-ban-is-risky-for-moscow-andworld-alike; Reuters, 2023. “Russian crude oil heads to UAE as sanctions divert flows.” https://www.reuters.com/business/energy/russian-crude-oil-heads-uae-sanctions-divert-flows-2023-03-06/; EIA (in-brief analysis), 2024. “Russia’s seaborne diesel trading partners shifted after Feb 2023 sanctions.” https://www.eia.gov/todayinenergy/detail.php?id=62044 14 CEDAR & Green Think Tank, 2026. “Shadow Routes: How Russia Learned to Live With Oil Sanctions.” Url: https://cedarus.io/research/oil-sanctions 15 Financial Times, 2023. “Vitol and Gunvor help keep Russian refined oil flowing, data shows.” https://www.ft.com/content/ba9754e3-6f4e-4455-b6be-c6c6edf6b853?syn-25a6b1a6=1 16 Fuels Europe, 2024. “Statistical Report 2024.” https://fuelseurope.eu/publications/publications/statisticalreport-2024; DW, 2023. “Russia's diesel exports: Who will the ban hit?” https://www.dw.com/en/russias-dieselexports-who-will-the-ban-hit/a-66929638 17 Bajo-Buenestado, Raúl, 2026. “Sanction Evasion and Industry Dynamics Disruptions: Evidence from Russian Diesel.” Unpublished working paper; Sicosa Energy. Quotes & market data. https://sicosaenergy.am/en/insights/ 18 The Telegraph, 2023. “German carmakers accused of supplying Putin’s Russia through the back door.” https://www.telegraph.co.uk/business/2023/12/05/german-carmakers-accused-of-supplying-putins-russiathrough/; Brooks, R. “Transshipments from Germany to Russia.” Brookings (commentary). https://www.brookings.edu/articles/transshipments-from-germany-to-russia/ 19 The Sofia Globe, 2022. “Bulgaria’s Exemption from Russian Oil Import Embargo Confirmed.” https://sofiaglobe.com/2022/06/03/bulgarias-exemption-from-russian-oil-import-embargo-confirmed/ 20 Dodonov, B. & Shapoval, N., 2025 “Options to complete the European ban on Russian fossil fuels.” https://kse.ua/wp-content/uploads/2025/03/Options EU_ban_on_Russian_fossil_fuels.pdf; Reuters, 2022. “EU agrees Russia oil embargo, gives Hungary exemptions; Zelenskiy vows more sanctions.” https://www.reuters.com/world/europe/best-we-could-get-eu-bows-hungarian-demands-agree-russian-oil-ban2022-05-31/ 21 Reuters, 2025. “EU won't ban Russian LNG until it secures alternatives, diplomats say.” https://www.reuters.com/world/europe/eu-wont-ban-russian-lng-until-it-secures-alternatives-diplomats-say2025-01-29/; Financial Times, 2026. “EU buys record amount of gas from Russia’s flagship plant.” https://www.ft.com/content/de9bbc3a-c317-4e5f-a324-6ec0dde45722?syn-25a6b1a6=1; Reuters, 2026. “EU imports record LNG volumes from Russia's biggest plant.” https://www.reuters.com/business/energy/euimports-record-lng-volumes-russias-biggest-plant-2026-07-13/ 22 Sturm, J., Menzel, K., & Schmitz, J. (2022). The simple economics of optimal sanctions: The case of EURussia energy trade. SSRN Working Paper 4084754; Kilian, L., Rapson, D., & Schipper, B. (2026). “The impact of the 2022 oil embargo and price cap on Russian oil prices.” The Energy Journal, 47(3), 1-39. 23 Brooks, R., Davidson, K., Harris. B., Hongju Koh, H. & Marshall, L., 2026. “Stiffening European sanctions against the Russian oil trade”. Brookings Report. https://www.brookings.edu/wpcontent/uploads/2026/01/20260203_ES_BrooksEtAl_EuropeSanctions_FINAL.pdf

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Itskhoki, O., & Mukhin, D. (2026). “Sanctions and the exchange rate.” Review of Economic Studies, 93(4), 2680-2714; Black, S. W., Christofides, C., & Mourmouras, A. (2006). “Convertibility risk: the precautionary demand for foreign currency in a crisis.” Annals of Finance, 2(2), 141-165. 25 Davis, S. & Patel, K. 2023. “Russian ruble buckles under trade sanctions, declining export earnings”. Federal Reserve Bank of Dallas blog. https://www.dallasfed.org/research/economics/2023/1010 26 Hamilton, J. D. (1983). “Oil and the macroeconomy since World War II.” Journal of political economy, 91(2), 228-248; Kilian, L. (2008). “The economic effects of energy price shocks.” Journal of Economic Literature, 46(4), 871-909. 27 Ishii, K., Macaire, C., & Stalla-Bourdillon, S., 2023. “China has reduced its energy bill thanks to Russian oil discounts.” Banque de France blog (#323). https://www.banque-france.fr/en/publications-andstatistics/publications/china-has-reduced-its-energy-bill-thanks-russian-oil-discounts 28 Amiti, M., Itskhoki, O., & Weinstein, D. 2024. “Global Supply Chains and U.S. Import Price Inflation”. Federal Reserve Bank of New Work (blog). https://libertystreeteconomics.newyorkfed.org/2024/03/global-supplychains-and-u-s-import-price-inflation/; Si Sano, M., Pongetti, G., Schuler, T., & Guan Toh, S. “Spillovers to the euro area from recent negative inflation in China”. European Central Bank - Published as part of the ECB Economic Bulletin, Issue 7/2023. https://www.ecb.europa.eu/press/economicbulletin/focus/2023/html/ecb.ebbox202307_03~97dbef6cf7.en.html 29 IEA, 2022. “Spain Oil Security Policy.” Report – International Energy Agency. https://www.iea.org/articles/spain-oil-security-policy; CORES database. https://www.cores.es/es/estadisticas 30 El País, 2026. “España dispara la compra de diésel a Marruecos entre denuncias de que viene de Russia.” https://elpais.com/economia/2026-07-02/espana-dispara-la-compra-de-diesel-a-marruecos-entre-denunciasde-que-viene-de-rusia.html 31 Bloomberg, 2023. “Russia’s Diesel Exports Heading for Record Despite EU Sanctions.” https://www.bloomberg.com/news/articles/2023-03-27/russia-s-diesel-exports-heading-for-record-despite-eusanctions 32 Kuik, F., Lis, E., Nickel, C., & Porqueddu, M. 2026 “From well to pump: how fuel prices are formed”. ECB blog. https://www.ecb.europa.eu/press/blog/date/2026/html/ecb.blog20260731~6224db57f8.en.html; Meyler, A. (2009). “The pass through of oil prices into euro area consumer liquid fuel prices in an environment of high and volatile oil prices.” Energy Economics, 31(6), 867-881.

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Europe’s Elusive Energy Security Equation

Anna Mikulska Nonresident Fellow

EU Energy and the New Dependency Debate Four years after Russia’s invasion of Ukraine, and four months into the effective closure of the Strait of Hormuz, Europe’s policy on energy security seems to be faltering, particularly when one looks at natural gas. The EU has fixated on a supposed danger of overdependence on American LNG, kept wiring billions of euros to Russia for the LNG it has legislated to ban, declined to build the contract portfolio that would stabilize its own prices, and drawn from the Middle East war the conclusion that fossil fuels as such are the main problem. These arguments misdiagnose the situation and leave the energy security equation unsolved. Europe has a good reason to be anxious about dependency. After all, overdependence on Russian natural gas supplies has been the main culprit behind Europe’s energy security problems following the 2022 Ukraine invasion. And while Norway, the largest EU supplier of natural gas (at 86 billion cubic meters, or bcm, and almost a third of all gas imports in 2025),1, 2 has been considered a safe (nearly domestic) option, this has not been the consensus about LNG produced in the United States, which, at 76 bcm, comprised 57.9 percent of the bloc’s LNG imports and about 27 percent of its total gas imports in 2025.3 In the first quarter of 2026 the U.S. share of Europe’s LNG imports reached 63 percent. Estimates are at about two-thirds for 2026, and at 75–80 percent of LNG imports by 2030 once Russian volumes are legislated out of the market.4, 5

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The political reaction has been swift. In January, after President Trump’s threats to seize Greenland from EU member Denmark, Energy Commissioner Dan Jorgensen called the episode “a wake-up call” and said there is “a growing concern that we risk replacing one dependency with another,” announcing a search for alternatives in Canada, Qatar, and North Africa.6 A cartoon circulating on European LinkedIn captures the mood: a wheel of fortune with American, Russian, and Qatari flags, captioned “please spin the wheel on who will determine the price of your heating this winter.” The joke reflects, at best, a lack of understanding or, at worst, a lack of consideration of how fundamentally different the three supply systems are.

US LNG: What It Is and What It Is Not Starting with the legal architecture: exports of U.S. LNG to countries without a free trade agreement require authorization from the Department of Energy under Section 3 of the Natural Gas Act, which directs DOE to grant applications unless it finds them inconsistent with the public interest.7 Once granted, an authorization is not a spigot the White House can turn. Indeed, U.S. law makes it remarkably difficult for any policymaker to turn off the tap. Exports to free trade partners are deemed in the public interest by statute and must be authorized “without modification or delay.” Exports to non-FTA countries, a category that includes the entire EU, are presumed lawful unless DOE affirmatively finds, after opportunity for a hearing, that they would harm the public interest.8 Modifying or rescinding an authorization already granted requires the same hearing plus a showing of good cause, and in the decade and a half of the export program this has never happened. The one attempt to slow the machine even modestly, the Biden administration’s January 2024 pause on approvals of new projects, touched no operating terminal and was still struck down by a federal court within six months, on the grounds that DOE was subverting Congress’s determination that LNG exports are presumptively in the public interest.9 Exports set records throughout the pause.10, 11 In reality, discretion in the statute runs toward approval and expeditious processing, with any restriction exposed to challenge in court.12, 13 Any U.S. President determined to halt flows to Europe would be left reaching for emergency statutes that have never been used to embargo energy sales to allies. That route would be in litigation from the first morning, with every contract holder on the other side of the courtroom, the European majors included.

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There are also more practical issues that anyone trying to halt U.S. LNG exports would need to face. U.S. natural gas is purchased from thousands of independent producers on an open, competitive pipeline grid. It is liquefied by private companies such as Cheniere, Venture Global, and Sempra. It is sold overwhelmingly free on board: title passes to the buyer at the loading dock, the buyer charters the ship, and no destination clause restricts where the cargo goes.14, 15 And who are the buyers? Frequently European ones. Shell, TotalEnergies, and BP rank among the largest holders of U.S. offtake, alongside European utilities and the Chinese and Indian portfolio players who resell into Europe at a margin. Of the roughly 23 bcm per year of long-term contracts signed with U.S. projects now under construction, 55 percent sits with European utilities and most of the rest with Europeanbased international oil companies.16 When a cargo lands at Zeebrugge, the counterparty exercising the contract is usually a European or global firm. The U.S. government appears nowhere in the transaction. And any action to limit the market would have to respond not only to extensive international pressure but also to domestic forces. This is very different from, for example, QatarEnergy, which is a single state-owned counterparty exporting from a single complex at Ras Laffan, through a single exit route that runs past Iran.17 Since March, that route has been blockaded, the complex has been hit, and force majeure notices to European buyers stretch into September.18, 19 Novatek, the main Russian LNG exporter, despite its designation as a “private” company, is far from independent of the Russian state, where energy is considered a source of state power.20 Yes, American supply carries risks of its own, and pretending otherwise would be foolish: price risk, weather risk, the reputational noise. But these are commercial risks that are priced daily and can be hedged. They differ from the sovereign, discretionary risk of a supplier who can decide, for reasons of state, that your natural gas flows stop.

The Dependency Europe Does Not Talk About While Brussels debates the American threat, the actual state-weaponized supplier is still being paid. Urgewald’s recent analysis of Kpler data shows that in the first six months of 2026 the EU received 136 of the 140 cargoes shipped worldwide from Russia’s Yamal LNG project, 97 percent of its output, worth an estimated €5.96 billion. EU-bound Yamal volumes rose 16 percent year on year even as Russia escalated missile and drone attacks on Ukrainian cities.21 Russian LNG supplied 13 percent of Europe’s LNG imports in the first quarter of 2026, a quarterly record for the EU, reached three months after the bloc adopted its import ban.

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Under the phase-out now in force, short-term Russian LNG purchases have been prohibited since April 25, 2026; long-term LNG contracts fall in January 2027; the last pipeline contracts end by October 1, 2027.22, 23 While the schedule is welcome, the record it must overcome is not encouraging. Buyers spent the early part of 2026 maximizing Russian intake ahead of the deadlines, and France, Belgium, and Spain hosted nearly all of it. A bloc that declares American gas a dependency risk while functioning as the logistical backbone of Russia’s Arctic LNG trade is, at best, confused about what dependency means. At worst it is misrepresenting how U.S. LNG works to avoid harder questions about its own choices. The hardest of those questions concerns contracts. European utilities could have secured U.S. volumes directly and on their own terms, if not before, then surely after the Russian invasion of Ukraine. For the most part they chose otherwise, wary of committing to twentyyear deals amid declining demand forecasts24 and an EU framework that bars long-term contracts for unabated gas beyond 2049.25 The consequence is structural spot exposure. The EU’s spot LNG requirement for 2026 is roughly 40 bcm, rising to about 56 bcm if Qatari production stays offline through December.26 It means Europe buys a third of its LNG at whatever the world price happens to be at the moment, including moments of constrained supply and greatest need. The exposure is compounded by regulation. EU law requires member states to fill gas storage to 90 percent of capacity within a window between October 1 and December 1 each year, with deviations of up to 15 percentage points in difficult market conditions.27 The 2025 amendment softened the old hard deadline for a telling reason: the mandate itself had been telegraphing Europe’s buying schedule to the market and inflating summer prices. A legally mandated buyer with a published deadline, no long-term contracts, and a war-tightened market is a price taker by default.

The Blockade and the Wrong Lesson The war that began with U.S. and Israeli strikes on Iran on February 28 reached the gas market within days. QatarEnergy declared force majeure and halted liquefaction in early March; Iran declared the Strait of Hormuz closed on March 4; roughly 20 percent of global LNG supply went offline.28, 29 TTF, Europe’s benchmark, jumped 76 percent in a week and crossed €60 per MWh by mid-March. An Iranian strike on Ras Laffan on March 18 removed 17 percent of Qatar’s export capacity for an estimated three to five years.30

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By late April, TTF futures stood 35 percent above pre-closure levels near $15 per MMBtu, while the U.S. benchmark Henry Hub had fallen 9 percent, insulated by domestic supply.31 Force majeure notices to European buyers now extend into September, and the July escalation in the Strait pushed TTF back above €50.32, 33 The lesson many in Europe are drawing is that geopolitical risk attaches to fossil fuel imports as such, regardless of origin, and that the answer is an accelerated exit into wind and solar, justified on security grounds independent of any climate consideration. A parallel prediction is easier to endorse: the war is driving a genuine European turn toward nuclear power.34 Nuclear genuinely diversifies, though it requires significant cost and time commitment. The renewables-only version of the argument collapses on any horizon that matters for the next decade.35, 36 Wind and solar are intermittent, their output depends on season and geography, and moving their electricity to demand centers requires grid expansion measured in years and hundreds of billions of euros. In the meantime, gas remains the balancing fuel; EU gas-fired generation rose 11 percent in 2025 precisely to back the system as coal declined.37 There is also a logical problem with the security case for electrifying everything. Diversification is the foundation of energy security. Concentrating heating, transport, and industry onto a single carrier, delivered over a single grid, is its opposite. Fossil fuels are not unsafe as a category; supply becomes unsafe when it is organized around a single statecontrolled seller, a single route, or a single price point (a lesson Europe should have learned following the Russian invasion of Ukraine). Conversely, it is safe when it is fungible, redundant, and contracted across a portfolio. That vulnerability was innate to Russian pipeline gas; it is true of Hormuz-locked Qatari LNG today, and it is precisely the vulnerability that flexible, multi-counterparty American supply has been attenuating.38

The Four A’s, Four Years On In my 2023 and 2024 congressional testimonies on European energy security after the Russian invasion of Ukraine, I argued that Europe failed when assessed against the four building blocks of energy security: availability, accessibility, affordability, and acceptability of supply.39 While some elements improved, my opinion has not substantively changed.

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Availability: Russia’s pipeline cuts, the Nord Stream sabotage, and the end of Ukrainian transit in January 2025 removed the volumes around which the European system was built. Global supply recovered on the back of American liquefaction. But the EU quickly turned negative toward “overdependency” on U.S. exports and quietly increased LNG imports from Russia! Additionally, availability rented on the spot market is conditional and could be pricey. In June 2026 Europe took less than half of U.S. LNG exports, its lowest share in two years, because Asian buyers paid nearly $4 per MMBtu more.40, 41 Without contracts, availability is an auction, and Europe does not always win. Accessibility: Regasification capacity reached nearly 215 bcm in 2025, up 8 percent, with additions in Belgium, Germany, Italy, and Poland.42 The buildout has since flattened. But the deeper problem has always been distribution. Spain alone holds 67 bcm of regasification capacity, close to a third of the EU total, yet remains poorly interconnected across the Pyrenees, an old deficiency I flagged in 2023 that persists unresolved.43 In the first quarter of 2026, nine EU terminals ran below 30 percent utilization, several of them Iberian, while nine others ran above 80 percent.44 Storage tells the same uneven tale: the EU entered last winter at 83 percent rather than the 95 percent of prior years, averaged 61 percent across 2025, down 22 points year on year, and exited the winter near one-third full.45, 46 Infrastructure that cannot move gas to meet demand does not deliver accessibility, however impressive it looks in aggregate. Affordability: The price history of natural gas is just as telling. Prices have never returned to baseline following 2022. TTF averaged €35 per MWh in January and February 2026, still roughly double pre-crisis norms; it crossed €60 in mid-March after the blockade; it averaged €45–53 through the spring; in mid-July it opened above €50 on the renewed Hormuz escalation.47, 48, 49 Through all of it, Henry Hub declined. The transatlantic spread of four to five times is a standing tax on European industry that its American competitors do not pay.50 The cumulative bill is staggering. EU member states spent about €281 billion on LNG between 2022 and 2025, spending rose almost 30 percent in 2025 alone, and roughly €100 billion of the total went to U.S. suppliers in 2022–2024.51, 52 The storage mandate then concentrates purchases into the summer window, guaranteeing that Europe bids against itself on the way to the October–December deadline. Gas sets electricity prices at the margin across most of the continent, so every one of these euros propagates into power bills and industrial competitiveness.

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Acceptability: This is where European policy works against itself most visibly. Official messaging declares fossil fuels a liability to be exited as fast as possible and blames them for high prices; gas is simultaneously indispensable as industrial feedstock and as backup for a renewables-heavy grid; long-term gas contracts are politically toxic and legally capped at 2049; Russian LNG is quietly acceptable at French, Belgian, and Spanish ports through 2026; and American LNG, the supply that actually kept the lights on after 2022, is framed as the next dangerous dependency.53, 54 These signals cannot all be acted on at once. A utility that cannot politically justify a twenty-year contract must buy spot. Spot exposure produces the volatility and price spikes that deepen public resentment of gas. The resentment makes contracts even harder to sign. Acceptability, the softest of the four variables, is now deepening the hardest problem: affordability.

Solving the Equation Europe has spent four years and several hundred billion euros discovering that energy security cannot be improvised. The variables of the equation are known—diversified suppliers, redundant infrastructure, contracted volumes, and a public conversation honest enough to permit all three.55, 56 None of this is mysterious, and none of it requires new theory. It requires the EU to act on the definition of energy security it already knows.

Notes 1

Council of the European Union, “Where Does the EU’s Gas Come From?” infographic, updated July 2026, https://www.consilium.europa.eu/en/infographics/where-does-the-eu-s-gas-come-from/. 2 European Commission quarterly gas market report data as summarized in “LNG Made Up 45 Percent of EU Gas Imports in 2025,” Rigzone, July 7, 2026, https://www.rigzone.com/news/lng_made_up_45_percent_of_eu_gas_imports_in_2025-07-jul-2026-184076article/. 3 European Commission quarterly gas market report data as summarized in “LNG Made Up 45 Percent of EU Gas Imports in 2025,” Rigzone, July 7, 2026, https://www.rigzone.com/news/lng_made_up_45_percent_of_eu_gas_imports_in_2025-07-jul-2026-184076article/. 4 Institute for Energy Economics and Financial Analysis (IEEFA), “European LNG Tracker,” May 2026 update, https://ieefa.org/european-lng-tracker. 5 “Two-Thirds of Europe’s LNG Imports to Come from the US amid Increased Reliance,” Euronews, May 13, 2026, https://www.euronews.com/business/2026/05/13/two-thirds-of-europes-lng-imports-to-come-from-theus-amid-increased-reliance; on the 80 percent projection and the June 2026 pullback, see “Dip in U.S. LNG Imports to EU Spells Trouble for Trade Deal,” OilPrice.com, July 2026, https://oilprice.com/Energy/EnergyGeneral/Dip-in-US-LNG-Imports-to-EU-Spells-Trouble-for-Trade-Deal.html.

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Agence France-Presse, “EU Energy Chief Says ‘Growing Concern’ over Dependency on US Gas,” Courthouse News Service, January 28, 2026, https://www.courthousenews.com/eu-energy-chief-says-growing-concernover-dependency-on-us-gas/. 7 15 U.S.C. § 717b(a) (Natural Gas Act, Section 3), https://www.law.cornell.edu/uscode/text/15/717b. Exports to free trade agreement countries “shall be granted without modification or delay”; supplemental orders affecting an existing authorization require opportunity for a hearing and good cause shown. 8 Congressional Research Service, “Executive Orders and U.S. LNG Exports: Frequently Asked Questions,” R48038, updated 2025, https://www.congress.gov/crs-product/R48038. 9 “Judge Overturns Biden’s LNG Export Pause,” E&E News by Politico, July 2024 (Louisiana v. Biden, W.D. La.), https://www.eenews.net/articles/judge-overturns-bidens-lng-export-pause/. 10 Anne-Sophie Corbeau, “Bridging the US-EU Trade Gap with US LNG Is More Complex than It Sounds,” Center on Global Energy Policy, Columbia University SIPA, May 1, 2025, https://www.energypolicy.columbia.edu/bridging-the-us-eu-trade-gap-with-us-lng-is-more-complex-than-itsounds/. 11 Kenneth B. Medlock III, “US LNG Exports: Truth and Consequence Revisited,” Baker Institute, February 17, 2025, https://www.bakerinstitute.org/research/us-lng-exports-truth-and-consequence-revisited. 12 Kenneth B. Medlock III, “Scenarios for Global Natural Gas Markets to 2050,” Baker Institute, March 20, 2025, https://www.bakerinstitute.org/research/scenarios-global-natural-gas-markets-2050. 13 Congressional Research Service, “The Natural Gas Act: Background, Key Provisions, and Policy Issues,” R48967, June 3, 2026, https://www.congress.gov/crs-product/R48967. 14 Michelle Michot Foss, Anna Mikulska, and Gürcan Gülen, eds., Monetizing Natural Gas in the New “New Deal” Economy (Palgrave Macmillan, 2021), https://link.springer.com/book/10.1007/978-3-030-59983-6. 15 Kenneth B. Medlock III, “The LNG-enie Is Out of the Bottle,” in Energy Insights 2025, Baker Institute, October 7, 2025, https://www.bakerinstitute.org/research/energy-insights-2025. 16 Anne-Sophie Corbeau, “Bridging the US-EU Trade Gap with US LNG Is More Complex than It Sounds,” Center on Global Energy Policy, Columbia University SIPA, May 1, 2025, https://www.energypolicy.columbia.edu/bridging-the-us-eu-trade-gap-with-us-lng-is-more-complex-than-itsounds/. 17 Kristian Coates Ulrichsen and Jim Krane, “Maritime Chokepoints and Risks to Global Shipping and Energy Security,” Baker Institute, March 16, 2026, https://www.bakerinstitute.org/research/maritime-chokepoints-andrisks-global-shipping-and-energy-security. 18 “QatarEnergy Declares Force Majeure on Some LNG Contracts Due to Iran War,” Al Jazeera, March 24, 2026, https://www.aljazeera.com/news/2026/3/24/qatarenergy-declares-force-majeure-on-some-lng-contracts. 19 “LNG Market Disruption: QatarEnergy Extends Force Majeure with Edison,” CNBC, July 1, 2026, https://www.cnbc.com/2026/07/01/qatarenergy-extend-force-majeure-september-italys-edison-iranwar-.html. 20 Anna Mikulska and Pawel Jakubowski, “The Future of Russian Gas: A Tale of Two Cities,” Baker Institute, June 29, 2020, https://www.bakerinstitute.org/research/future-russian-gas-tale-two-cities. 21 Urgewald, “EU Paid an Estimated €5.96 Billion for Russian Arctic LNG in the First 6 Months of 2026,” press release, July 13, 2026, https://www.urgewald.org/en/media/eu-paid-estimated-eu596-billion-russian-arctic-lngfirst-6-months-2026. 22 IEEFA, “European LNG Tracker” (Russian LNG at 13 percent of European imports in Q1 2026, a quarterly record for the EU; phase-out dates for short-term and long-term Russian LNG and pipeline contracts), https://ieefa.org/european-lng-tracker; Council of the European Union, “Where Does the EU’s Gas Come From?” https://www.consilium.europa.eu/en/infographics/where-does-the-eu-s-gas-come-from/.

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Gabriel Collins, Anna B. Mikulska, and Steven R. Miles, “Winning the Long War in Ukraine Requires Gas Geoeconomics,” Baker Institute, August 4, 2022, https://www.bakerinstitute.org/research/winning-long-warukraine-requires-gas-geoeconomics. 24 Christina Boufarah, Kristian Coates Ulrichsen, Ally Godsil, Jim Krane, and Ana Martín Gil, “Global Energy: Qatar’s LNG Expansion,” Baker Institute, May 10, 2024, https://www.bakerinstitute.org/research/global-energyqatars-lng-expansion. 25 Anne-Sophie Corbeau, “Bridging the US-EU Trade Gap with US LNG Is More Complex than It Sounds,” Center on Global Energy Policy, Columbia University SIPA, May 1, 2025, https://www.energypolicy.columbia.edu/bridging-the-us-eu-trade-gap-with-us-lng-is-more-complex-than-itsounds/. 26 ACER, “Key Developments in European Gas Markets: Winter Season 2025–2026,” April 2026, https://www.acer.europa.eu/sites/default/files/documents/Publications/2026-ACER-Gas-Key-Developmentswinter.pdf. 27 Council of the European Union, “Gas Storage: Council Greenlights 2-Year Extension of Reserves Filling Rules to Safeguard Winter Supply,” press release, July 18, 2025, https://www.consilium.europa.eu/en/press/pressreleases/2025/07/18/gas-storage-council-greenlights-2-year-extension-of-reserves-filling-rules-to-safeguardwinter-supply/; on the amended Regulation (EU) 2025/1733 in detail, see Oxford Institute for Energy Studies, “EU Gas Storage Regulation: A Journey from Crisis-Induced Rigidity to Increased Flexibility,” November 2025, https://www.oxfordenergy.org/publications/eu-gas-storage-regulation-a-journey-from-crisis-induced-rigidityto-increased-flexibility/. 28 “QatarEnergy Declares Force Majeure on Some LNG Contracts Due to Iran War,” Al Jazeera, March 24, 2026, https://www.aljazeera.com/news/2026/3/24/qatarenergy-declares-force-majeure-on-some-lng-contracts. 29 “Natural Gas, LNG Prices Soar on Middle East Supply Fears,” CNBC, March 3, 2026, https://www.cnbc.com/2026/03/03/middle-east-war-gas-energy-lng-drone-qatar-strait-hormuz-priceshock.html. 30 Jim Krane and Justin Alexander, “Losing Hormuz: The Costs of War for Gulf Oil Exporters,” Baker Institute, April 8, 2026, https://www.bakerinstitute.org/research/losing-hormuz-costs-war-gulf-oil-exporters. 31 U.S. Energy Information Administration, “International LNG Prices Rise amid Strait of Hormuz Closure,” Today in Energy, April 28, 2026, https://www.eia.gov/todayinenergy/detail.php?id=67604. 32 “LNG Market Disruption: QatarEnergy Extends Force Majeure with Edison,” CNBC, July 1, 2026, https://www.cnbc.com/2026/07/01/qatarenergy-extend-force-majeure-september-italys-edison-iranwar-.html. 33 “European Natural Gas Prices Jump on Hormuz Escalation,” OilPrice.com via Yahoo Finance, July 13, 2026, https://finance.yahoo.com/energy/articles/european-natural-gas-prices-jump-074500768.html. 34 “Greece ‘Turning the Page’ on Nuclear Energy, Says PM Mitsotakis,” NucNet, March 11, 2026, https://www.nucnet.org/news/greece-turning-the-page-on-nuclear-energy-says-pm-mitsotakis-3-3-2026. 35 Michelle Michot Foss, “‘Energy and Material Realism’ and Its Discontents,” in Energy Insights 2025, Baker Institute, October 7, 2025, https://www.bakerinstitute.org/research/energy-insights-2025. 36 Gabriel Collins and Michelle Michot Foss, “The Global Energy Transition’s Looming Valley of Death,” Baker Institute, January 27, 2022, https://www.bakerinstitute.org/research/global-energy-transitions-looming-valleydeath. 37 European Commission quarterly gas market report data as summarized in “LNG Made Up 45 Percent of EU Gas Imports in 2025,” Rigzone, July 7, 2026, https://www.rigzone.com/news/lng_made_up_45_percent_of_eu_gas_imports_in_2025-07-jul-2026-184076article/.

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Gabriel Collins and Anna B. Mikulska, “Gas Geoeconomics in Europe: Using Strategic Investments to Promote Market Liberalization, Counterbalance Russian Revanchism, and Enhance European Energy Security,” Baker Institute, May 31, 2018, https://www.bakerinstitute.org/research/egas-geoeconomics-europe. 39 Anna Mikulska, Testimony to the Senate Committee on Energy and Natural Resources, “One Year Later: The Impact of the Russian Federation’s War in Ukraine on European and Global Energy Security,” February 16, 2023, https://www.energy.senate.gov/services/files/361B439A-B3DC-4A28-9D32-419D69FAE0C3; Anna B. Mikulska, “Energy Security in Europe More than Two Years into Russian Invasion on Ukraine,” IDA Science and Technology Policy Institute, remarks delivered at the U.S. Helsinki Commission briefing “The Future of European Energy Security,” October 16, 2024, https://www.csce.gov/briefings/the-future-of-european-energysecurity/. 40 “Dip in U.S. LNG Imports to EU Spells Trouble for Trade Deal,” OilPrice.com, July 2026, https://oilprice.com/Energy/Energy-General/Dip-in-US-LNG-Imports-to-EU-Spells-Trouble-for-Trade-Deal.html. 41 Gabriel Collins, “Reality Is Setting In: Asian Countries To Lead Transitions in 2024 and 2025,” Baker Institute, August 22, 2024, https://www.bakerinstitute.org/research/reality-setting-asian-countries-lead-transitions2024-and-2025. 42 European Commission quarterly gas market report data as summarized in “LNG Made Up 45 Percent of EU Gas Imports in 2025,” Rigzone, July 7, 2026, https://www.rigzone.com/news/lng_made_up_45_percent_of_eu_gas_imports_in_2025-07-jul-2026-184076article/. 43 Anna Mikulska, Testimony to the Senate Committee on Energy and Natural Resources, “One Year Later: The Impact of the Russian Federation’s War in Ukraine on European and Global Energy Security,” February 16, 2023, https://www.energy.senate.gov/services/files/361B439A-B3DC-4A28-9D32-419D69FAE0C3; Spanish regasification capacity from IEEFA, “European LNG Tracker,” https://ieefa.org/european-lng-tracker. 44 Institute for Energy Economics and Financial Analysis (IEEFA), “European LNG Tracker,” May 2026 update, https://ieefa.org/european-lng-tracker. 45 European Commission, “Gas Storage” (EU storage at 83 percent on October 1, 2025), https://energy.ec.europa.eu/topics/energy-security/gas-storage_en. 46 European Commission quarterly gas market report data as summarized in “LNG Made Up 45 Percent of EU Gas Imports in 2025,” Rigzone, July 7, 2026, https://www.rigzone.com/news/lng_made_up_45_percent_of_eu_gas_imports_in_2025-07-jul-2026-184076article/. 47 Monthly TTF price averages as compiled in Urgewald, “EU Paid an Estimated €5.96 Billion for Russian Arctic LNG in the First 6 Months of 2026,” press release, July 13, 2026, https://www.urgewald.org/en/media/eu-paidestimated-eu596-billion-russian-arctic-lng-first-6-months-2026. 48 “Natural Gas, LNG Prices Soar on Middle East Supply Fears,” CNBC, March 3, 2026, https://www.cnbc.com/2026/03/03/middle-east-war-gas-energy-lng-drone-qatar-strait-hormuz-priceshock.html.

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“European Natural Gas Prices Jump on Hormuz Escalation,” OilPrice.com via Yahoo Finance, July 13, 2026, https://finance.yahoo.com/energy/articles/european-natural-gas-prices-jump-074500768.html. 50 U.S. Energy Information Administration, “International LNG Prices Rise amid Strait of Hormuz Closure,” Today in Energy, April 28, 2026, https://www.eia.gov/todayinenergy/detail.php?id=67604. 51 Institute for Energy Economics and Financial Analysis (IEEFA), “European LNG Tracker,” May 2026 update, https://ieefa.org/european-lng-tracker. 52 “US LNG Exports to Europe Surge, Raising Risk of New Dependency,” Brussels Signal, December 22, 2025 (IEEFA analyst Ana Maria Jaller-Makarewicz on relative cost; roughly €100 billion paid for U.S. LNG in 2022– 2024), https://brusselssignal.eu/2025/12/us-lng-exports-to-europe-surge-raising-risk-of-new-dependency/. 53 Anne-Sophie Corbeau, “Bridging the US-EU Trade Gap with US LNG Is More Complex than It Sounds,” Center on Global Energy Policy, Columbia University SIPA, May 1, 2025, https://www.energypolicy.columbia.edu/bridging-the-us-eu-trade-gap-with-us-lng-is-more-complex-than-itsounds/. 54 Urgewald, “EU Paid an Estimated €5.96 Billion for Russian Arctic LNG in the First 6 Months of 2026,” press release, July 13, 2026, https://www.urgewald.org/en/media/eu-paid-estimated-eu596-billion-russian-arctic-lngfirst-6-months-2026. 55 Jim Krane and Kenneth B. Medlock III, “Geopolitical Dimensions of US Oil Security,” Energy Policy 114 (2018), https://doi.org/10.1016/j.enpol.2017.12.050. 56 Kenneth B. Medlock III, “Energy Security and Supply Chain Resilience,” in Energy Insights 2025, Baker Institute, October 7, 2025, https://www.bakerinstitute.org/research/energy-insights-2025

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ENERGY AND GEOPOLITICS IN EURASIA

What Went Wrong With the European Energy Transition? Michał Kurtyka Director’s Council Fellow

Introduction In the winter of 2022, something broke in Europe’s relationship with energy. Benchmark gas prices surged to levels that would have seemed impossible a decade earlier. Aluminum smelters and fertilizer plants across the continent began shutting their doors—not because of a war on their soil, but because of its knock-on effects on markets that European policymakers had assumed were safely managed. Governments scrambled to find liquefied natural gas from the United States, Qatar, and Africa, often outbidding buyers in South Asia who had fewer alternatives. In August of that year, a cargo of LNG originally contracted for Bangladesh was diverted to Europe; Dhaka faced acute power shortages in the weeks that followed, contributing to a broader economic crisis.1 The energy transition was supposed to make Europe more secure. For a moment, it seemed to have made it more fragile. The immediate cause was Russia’s full-scale invasion of Ukraine and the resulting weaponization of pipeline gas. But the deeper causes were structural, accumulated over two decades of energy policymaking in Brussels, Berlin, Paris, and other European capitals. Understanding what went wrong—and why—is not an argument against the energy transition. It is an argument for redesigning it. The question is no longer whether Europe should decarbonize. The question is whether democracies can still redesign the transition before their rivals, their voters, and physics redesign it for them. The transition can be evaluated by four tests: emissions integrity, industrial competitiveness, system resilience, and geopolitical autonomy. On the first of these tests, Europe has recorded real progress. On the remaining three, the record is one of systematic underperformance, and structural choices that made failure more likely.

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The Ledger: Real Achievement and Their Hidden Costs Seen from a certain angle, the European energy transition has been a genuine achievement. Between 1990 and 2023, EU greenhouse gas emissions fell by approximately 37 percent, even as the global total continued to rise.2 Renewable electricity’s share in the EU mix grew from around 6 percent in 2000 (wind and solar specifically; total renewables including large hydro were higher) to 44 percent in 2023, with wind and solar alone accounting for close to a quarter of generation.3 Europe created the world’s largest carbon market, helped drive down the cost of wind and solar globally, and developed institutions, regulations, and political coalitions that gave the green transition a scaffolding that no other major economy had attempted at similar scale. These are not trivial accomplishments. But the headline numbers conceal a more troubling pattern. Much of Europe’s apparent emissions success rests on what economists call carbon leakage: the export of emissionintensive production to other parts of the world, where environmental standards are often lower. In 2023, more than 20 percent of Europe’s emissions were effectively imported, embedded in goods and services produced abroad.4 In Sweden, consumption-based accounting suggests that more than 60 percent of the country’s actual carbon footprint originates outside its borders.5 The chimneys disappeared; the appetite for the products that fueled them did not. A second, less visible source of emission reductions has been demand destruction—the contraction of energy-intensive industrial activity rather than its decarbonization. The International Energy Agency estimates that between 2022 and 2024, a significant share of the EU’s emissions decline came not from cleaner technology but from collapsing industrial energy demand. EU gas consumption dropped by around 13 to 14 percent in 2022 alone, and industrial gas use has remained roughly 10 to 20 percent below pre-crisis levels since.6 According to IEA’s medium-term projections, roughly half of this lost demand is unlikely to return by 2030, as shuttered capacity and energy-intensive production shift permanently to regions with cheaper and more stable energy.7 The chemical sector illustrates what this means in practice. Between 2022 and 2025, announced closures of European chemical production capacity surged, erasing roughly nine percent of the continent’s capacity. In nearly half of these cases, companies pointed directly to energy-cost competitiveness as the decisive factor. New investment in production capacity, meanwhile, fell from 2.7 million tons in 2022 to 0.3 million tons in 2025.8

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The automotive sector tells a parallel story. German automotive employment fell from 841,000 in 2019 to 711,000 in 2026—a loss of 130,000 jobs—and Volkswagen Group announced further cuts of 50,000 positions in early 2026.9 What had once been Europe’s industrial locomotive was losing traction. This is not simply an unfortunate side effect of an otherwise sound strategy. It is, in significant part, the consequence of how Europe chose to shape its energy system over two decades: privileging politics over markets, regulatory ambition over technological diversity, and inward coherence over geopolitical realism.

Politics Over Markets Europe prides itself on rules, markets, and technocratic rigor. In energy, the reality has often been different. Targets for emissions reductions, renewable deployment, and efficiency improvements have frequently been negotiated as symbols of political ambition rather than outputs of sober assessments of technology, capital availability, or realistic timelines. Since the first formulation of European climate policy in 2008—the so-called “3×20” framework, which set goals of 20 percent emissions reduction, 20 percent renewables, and 20 percent efficiency improvement by 2020—the logic of political target-setting has dominated. The institutional choreography of European energy governance amplifies this tendency. Heads of government in the European Council agree on headline numbers. The European Commission translates them into dense legislative packages. The European Parliament pushes the envelope further. Along the way, compromises are struck, exemptions carved out, and the final result is what one observer has aptly called “an increasingly complicated patchwork of multi-layered compromises rather than a coherent set of policy rules defining innovation-oriented markets.” The European Commission’s own evolution has deepened this dynamic. Originally conceived as the “guardian of the Treaties”—a neutral arbiter ensuring that European rules were applied consistently across member states—the Commission has, over the past two decades, increasingly declared itself “political.” When Jean-Claude Juncker became Commission President in 2014, he was explicit that his would be a political, not merely technocratic, institution. His successor, Ursula von der Leyen, carried this further, making the European Green Deal the central project of her first term. As the energy transition became indistinguishable from the European project, the latter became increasingly synonymous with the expansion of the Commission’s regulatory powers. 219

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This shift had consequences. A study drawing on quantitative textual analysis of the European Commission’s open consultations found that environmental associations consistently outperformed mainstream business interests in shaping EU environmental legislation, despite the latter’s numerical dominance in the lobbying landscape.10 The Commission systematically aligned its positions with pro-environmental outcomes—a pattern that produced important achievements but also a systematic underweighting of competitiveness, industrial strategy, and energy security in the policy calculus. The result, in regulatory terms, was an avalanche. The average EU legal act has nearly doubled in length since the early 2000s, and the European Commission now produces close to 20 million words in legal acts annually—more than seven times the annual production of the post-Maastricht era.11 Complicated regulation favors insiders; simple rules enable competition. With increasingly sophisticated legal frameworks, investing in influencing regulators in Brussels became more rewarding than winning in markets. Stronger, betterconnected countries captured agenda-setting power; others were left to follow rules they had little role in shaping. Germany offers the most instructive example of how this played out. For years, Berlin combined a powerful manufacturing base, access to cheap Russian gas, and an outsized voice in Brussels. That combination allowed Germany to export its own energy model— Energiewende—as the template for European policy, while quietly shielding its most energyintensive industries from some of the costs. When the energy shock came, Germany announced a €200 billion “defensive shield” to cap gas and electricity prices for domestic industry, a scale of intervention that few other member states could match.12 The energy crisis was thus absorbed very differently across the single market, depending not on strategic coherence but on fiscal firepower.

Regulatory Ambition Over Technological Diversity The second structural failure was the premature closure of the technology question. From the earliest stages of European climate policy, renewables—particularly wind and solar— were not simply a preferred option; they became the answer before the full range of questions had been asked. Germany’s Energiewende elevated the rejection of nuclear power to the status of a moral boundary marker and exported that sensibility to Brussels. France, paradoxically, reduced its commitment to nuclear generation in an effort to align with European norms, constraining EDF’s financial capacity to maintain and build new plants.13

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The consequences of this technological narrowing were significant. Successive EU support schemes—feed-in tariffs, priority dispatch, dedicated auctions—accelerated the deployment of wind and solar with impressive results. But they did so at the expense of what economists call technological neutrality, which is the principle that policy should set the goal and let markets discover the most efficient path to it. The goal—decarbonization—was defined in advance to require a specific set of technologies, which is not the same thing. Variable renewable sources—those dependent on wind and sun—introduce system costs that are invisible in deployment targets but highly visible in market outcomes. When wind and solar move from five percent of the electricity mix to forty percent, the need for backup dispatchable capacity, grid reinforcement, and storage does not disappear; it grows. In practice, this requires sustaining two parallel energy systems: one powered by intermittent renewables, and one capable of compensating for their absences. A study examining the Texas electricity market found that displacing fossil fuels with wind and storage is approximately 28 percent more expensive than doing so with nuclear and storage.14 The European system has faced analogous tensions, though they are rarely presented in these terms. Grid development suffered from the same logic. Zonal pricing—maintaining uniform electricity prices within countries for social and political reasons—was preserved long after its incompatibility with a high-renewables system became apparent. Germany’s failure to develop adequate north-south transmission capacity created loop flows that disrupted neighboring markets for years, until regulatory pressure finally compelled action.15 Hard-toabate sectors—cement, steel, glass, ammonia—were placed under carbon price obligations before credible decarbonization pathways for those industries existed, compounding competitive disadvantage without accelerating technological solutions. The IEA’s own medium-term assessments have acknowledged that grid congestion and system bottlenecks have limited the return on the renewable investment surge of the preceding decade. The sentiment was captured bluntly by infrastructure investors. As one major asset manager’s 2025 assessment put it, the net-zero investment boom “made renewable energy cost competitive but did not resolve system bottlenecks” with the result that fossil fuels and nuclear remain “substantially underinvested relative to forward demand expectations.”16 When problems emerged—grid strain, dependence on Chinese suppliers, cost burdens on consumers and industry—the dominant policy reflex was not to re-examine assumptions but to accelerate the same favored options. 221

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Failing to meet an interim target triggered not a reconsideration of the approach but a tightening of future obligations. The gap between what was promised and what was likely on current trends kept widening. Credibility eroded. But on paper, Europe remained the world’s climate champion. This “doubling down” reflex became a defining feature of European climate governance. The European Parliament, which cannot set initial targets or control the means to achieve them, found that raising ambition was, in practice, the only available lever over member states. Non-achievement of past objectives was thus covered not by accountability but by escalation: tighter future targets, new layers of obligation, and the implicit theory that higher declared ambition would somehow force the means to materialize. Several of Europe’s most prominent emissions-reduction milestones were ultimately reached not because of the policy instruments designed to achieve them, but because of COVID-19 lockdowns and the industrial contraction that followed Russia’s invasion of Ukraine. A governance system that cannot distinguish between genuine decarbonization and economic collapse has a measurement problem as much as a policy one. The ideological logic of the transition also gave rise to a more radical current: degrowth. A strand within the European Parliament and parts of the climate advocacy community argued that if emissions are inextricably coupled to economic activity, the logical conclusion is a deliberate reduction in that activity. Green growth—the proposition that decarbonization and prosperity can advance together—was offered as an alternative, but the degrowth sensibility deepened public unease in constituencies that experienced the transition primarily as loss rather than opportunity. More damagingly, it handed critics a potent target: the charge that the green agenda was less about energy security or industrial modernization than about managing Europe’s descent into a smaller version of itself. The transition paid a political price for that association; it has not fully recovered.

Inward Coherence Over Geopolitical Realism The third failure was geopolitical, though its roots were cultural and historical. European integration was built on an inward logic: to bind France and Germany so tightly together that war between them would become unthinkable. From the European Coal and Steel Community to the Common Market to the single currency, the project was about solving European problems. Energy policy followed the same template: a matter of internal markets, social cohesion, and environmental progress inside the bloc.

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When the Lisbon Strategy was unveiled in 2000, pledging to make the EU “the most competitive and dynamic knowledge-based economy in the world,” China’s economy was still roughly equivalent in size to France’s. Two decades later, China’s GDP is approximately six times larger than France’s. In 2000, Europe imported more oil than Asia; now Asia accounts for roughly 60 percent of global oil imports, with Europe’s share shrinking accordingly.17 The continent’s gravitational pull in global commodity markets, supply chains, and diplomatic forums has diminished substantially, even as its regulatory ambitions have continued to expand. The dominant European framework for managing external relationships—Wandel Durch Handel, i.e., change through trade—rested on the conviction that economic interdependence would gradually transform the behavior of partners, including authoritarian ones. Applied to Russia, this produced two decades of deepening dependence on pipeline gas, culminating in Nord Stream 2, a project that many European governments defended almost until the moment it became untenable. Applied to China, it produced a situation where Europe became a sales market for goods that China could produce at lower cost, while Beijing built dominant positions in the supply chains that Europe’s own energy transition required. Today, every step of the European energy transition reinforces external dependencies rather than reducing them. The scramble for LNG following the Russian supply cut reinforced the leverage of U.S. exporters in Transatlantic negotiations and generated the Bangladesh episode—a vivid illustration of how European energy insecurity exports instability to more vulnerable countries. Europe’s hunger for solar panels, batteries, and refined critical minerals cements China’s position at the center of clean-technology supply chains. The European Commission’s own Critical Raw Materials Act acknowledged that the EU imports approximately 98 percent of its rare earth elements from a single country and more than 70 percent of its lithium—figures that make the concept of clean-energy sovereignty partly illusory without fundamental supply chain diversification.18 Its own industrial policies—still modest in comparison to U.S. subsidies under the Inflation Reduction Act or Chinese industrial finance—struggle to close the gap. The continent has found itself caught between two competing visions of the energy future—the American molecule-based model of hydrocarbon abundance and the Chinese electron-based model of manufactured cleantechnology dominance—with no coherent European alternative in sight. Europe’s declining weight in global emissions makes this strategic picture more, not less, urgent. In 1990, the EU was responsible for approximately 25 percent of global greenhouse gas emissions. By 2023, that share had fallen to around 7 to 8 percent.19 223

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Even a complete decarbonization of the European economy—an outcome that lies well beyond current trajectories—would not in itself resolve the global emissions trajectory. What Europe does matters less in terms of direct atmospheric impact than it once did. What matters more is whether Europe can demonstrate that the transition is compatible with prosperity, security, and social cohesion, making it a model worth following, rather than a cautionary tale. The contest for that narrative is already underway. European climate leadership, once largely uncontested, is now actively challenged by governments across the Global South. Brazil, host of COP30, issued new deep-water oil exploration permits in the months before the conference. Indonesia’s government has resisted Western pressure on coal phase-out timelines. The argument heard with increasing frequency—that Europe benefited from cheap fossil fuels during its own industrialization and has no standing to constrain the development choices of others—has gained traction precisely as Europe’s own energy policy has become more visibly costly and more geopolitically dependent.

The Price of Inattention to Infrastructure Behind the political failures and the geopolitical blind spots lies a more prosaic but equally consequential set of errors: the systematic underestimation of what energy transition requires in physical, financial, and institutional terms. Grid infrastructure is the most striking example. The rapid expansion of variable renewable generation requires not only new transmission capacity but a fundamental redesign of electricity markets. Zonal pricing kept electricity prices uniform within national borders for political reasons, and created systematic distortions that accumulated over years, producing perverse investment incentives, cross-border loop flows, and market fragmentation that raised costs for consumers and impeded the integration needed for a genuine European energy system. The governance of electricity grids remained predominantly national even as the physics of the system became increasingly continental. Energy price volatility, meanwhile, has become structurally embedded in European industry’s operating environment in ways that may prove more damaging than the absolute level of prices. A European Central Bank study covering European listed companies between 1999 and 2022 found that an energy price shock increasing producer costs by one percent led to a 2.9 percent decline in capital expenditure in the same year, followed by a 4.1 percent decline in the following year.20 Energy Insights 2026

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For energy-intensive sectors, the combination of high average costs and unpredictable swings is particularly corrosive. Firms can manage high prices through contracts and hedging; they cannot easily justify decade-long investments in new capacity when the single most important input has begun to behave like a speculative asset. Investment committees dislike coin tosses. The European Investment Bank’s 2024 survey found that energy costs represented a significant burden for 46 percent of European companies—a far higher share than in the United States.21 According to IEA data, average industrial electricity prices in the EU were approximately double those in the United States in 2023—a structural gap that had widened substantially from pre-2019 levels.22 Since mid-2022, the European Central Bank has identified energy-cost competitiveness as a principal brake on European exports.[iii] These are not cyclical difficulties that will resolve themselves when energy markets stabilize. They reflect structural choices about how the energy system was designed and who bore the costs of those choices. The social dimension of these costs has been similarly underestimated. European energy policy was designed with significant attention to environmental ambition and market design, but with insufficient attention to the distributional question: who pays and how much. The answer, in practice, has been that the costs of the transition have fallen disproportionately on lower-income households, energy-intensive workers, and regions historically dependent on fossil fuels. Governments have responded with large-scale intervention—announcing subsidy packages across Europe that totaled approximately €750 billion in response to the 2022 price shock24—but these interventions were reactive, poorly targeted, and fiscally unsustainable as permanent fixtures of energy policy.

Rethinking Transition Pathways None of this is an argument for abandoning energy transitions. The physical case for decarbonization has not changed, and the political and social costs of inaction would dwarf those of a well-designed transition. But the model that has governed European energy policy for two decades has reached its limits. The question is not whether to transition, but how to do it differently.

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Three principles are important for guiding a next-generation approach. The first is the restoration of genuine technological neutrality. Europe has spent two decades presupposing an answer—renewables—only to discover that reality is more complicated. A realistic decarbonization strategy must include dispatchable low-carbon generation. In practice, this includes next-generation nuclear power, natural gas with carbon capture, hydrogen produced via multiple pathways, and technologies that do not yet exist. However, this requires setting clear, stable, long-term price signals that allow markets—from private capital investors to engineering talent—to discover what actually works, rather than prescribing a specific technology mix from the start. The technology deployed is less important than the outcome: affordable, reliable, low-carbon energy that can underpin a competitive industrial economy. The second is a fundamental reorientation of market design. Europe’s historic strength has been its ability to create large, competitive markets underpinned by the rule of law. In energy, that strength has been progressively undermined by the accumulation of overlapping support schemes, emergency interventions, national exemptions, and asymmetric state aid. The path back is not deregulation in the abstract but a coherent reform of electricity market design—including grid governance, pricing, and investment incentives—oriented around system efficiency rather than technology preference. Kenneth Medlock of Rice University’s Baker Institute has argued that energy security is improved when policy allows trade to occur unimpeded, production to expand without inefficient encumbrances, and new technologies to proliferate and increase competition among endusers.25 That description is not currently a fair characterization of European energy policy, but it should be the target. The third is a strategic reframing of European energy policy with geopolitical dimensions— not merely as climate or market policy. The supply shock of 2022 was a warning about gas dependency on Russia. The next version of the same vulnerability could involve critical minerals from the Democratic Republic of Congo, battery cells from China, or electrolyzers and power electronics whose supply chains run through a handful of non-European manufacturers. Diversification of supply chains, investment in European industrial capacity for key transition technologies, and active trade diplomacy—including genuine partnerships with resource-rich developing countries that offer something beyond carbon-border levies— are as essential to a durable energy transition as any renewable energy target. Europe cannot decarbonize its economy while remaining strategically dependent on actors whose interests do not align. Energy Insights 2026

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These three principles add up to a different kind of energy project: one that is less morally declaratory but more strategically grounded; less focused on targets and regulatory accumulation but more focused on outcomes and institutional capacity; and less inwardfacing but more attuned to the competitive and geopolitical environment in which Europe actually operates.

Rescuing Europe’s Transition From Its Illusions Europe’s energy transition was supposed to be a masterstroke: a way to combine climate leadership with industrial modernization, strategic sovereignty, and moral authority on the world stage. That ambition was not wrong. What went wrong was the assumption that ambition could substitute for strategy—that if the political will was declared loudly enough, the economics, the physics, and the geopolitics would fall into line. They did not. Instead, the economics produced deindustrialization and energy poverty; the physics produced grid congestion, system fragility, and the uncomfortable realization that a power system built on variable renewables without adequate backup is a power system that fails when the wind stops; and the geopolitics produced new dependencies that, in some respects, are more structurally embedded than the ones they replaced. Europe still has the assets to get this right: sophisticated financial markets, world-class engineering, a regulatory tradition that can create market certainty when it is properly focused, and a democratic legitimacy that authoritarian competitors lack. But using those assets requires a different kind of leadership than the one that has dominated the past two decades. It must be willing to acknowledge that the transition has been, in important respects, poorly designed; willing to make the harder choices about grid infrastructure, nuclear power, industrial competitiveness, and supply chain resilience; and willing to tell citizens the truth about costs and trade-offs rather than offering the comforting illusion that decarbonization is free. A successful energy transition will not come from more targets, more regulations, or more declarations of ambition. It will come from the unglamorous work of rebuilding energy policy on the harder foundations of technological realism, competitive markets, and cleareyed geopolitical strategy. The stakes—for European prosperity, for European security, and for the credibility of democratic climate leadership globally—could hardly be higher. 227

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Notes 1

On the Bangladesh LNG diversion of August 2022: Reuters, “As Europe scrambles for gas, energy-poor nations are left further behind,” 19 August 2022, https://www.reuters.com; Bloomberg, “LNG armada heads to Europe, leaving Asia scrambling for supplies,” August 2022. Power shortages and economic pressures in Bangladesh in this period are documented by the Bangladesh Power Development Board and the World Bank’s Bangladesh Economic Update, Q3 2022. The direct causal chain between a single LNG diversion and the broader economic crisis is complex; this passage identifies a contributing factor in a context of multiple pressures. 2 European Environment Agency, “Total greenhouse gas emission trends and projections in Europe,” EEA, 2024. https://www.eea.europa.eu/en/analysis/indicators/total-greenhouse-gas-emission-trends 3 Ember, “European Electricity Review 2024,” Ember, 2024. https://emberclimate.org/insights/research/european-electricity-review-2024/ 4 Eurostat, “Greenhouse gas emission footprints,” Statistics Explained, 2024. https://ec.europa.eu/eurostat/statistics-explained/index.php?title=Greenhouse_gas_emission_footprints 5 Naturvårdsverket (Swedish Environmental Protection Agency), “Konsumtionsbaserade växthusgasutsläpp per person,” 2023. https://www.naturvardsverket.se/data-och-statistik/klimat/konsumtionsbaseradevaxthusgasutslapp-per-person/. See also Eurostat consumption-based accounting data, “Greenhouse gas emission footprints,” 2024. 6 International Energy Agency, “Gas Market Lessons from the 2022–2023 Energy Crisis,” IEA, 2023. https://iea.blob.core.windows.net/assets/beef8adc-fb45-4987-9bac41ead9345f91/GasMarketLessonsfromthe2022-2023EnergyCrisis.pdf 7 S&P Global, “OECD European gas demand forecast to fall up to 10% from 2024–2030: IEA,” October 2025. https://www.spglobal.com/energy/en/news-research/latest-news/lng/102725-oecd-european-gas-demandforecast-to-fall-up-to-10-from-2024-2030-iea 8 Cefic, “European Chemical Closures & Investments Radar 2022–2025,” Cefic, 2025. https://cefic.org/resources/european-chemical-closures-investments-radar-2022-2025/ 9 VDA (Verband der Automobilindustrie), “Jahresbericht 2025,” VDA, 2025. https://www.vda.de; Volkswagen AG, “Volkswagen Group on course: strategic transformation with stronger focus on performance,” press release, November 2024. https://www.volkswagen-group.com. The 2026 employment figure incorporates announced restructuring programmes and should be understood as a projection based on confirmed cuts rather than finalized Eurostat data. 10 Belis, S.P., “Lobbying the European Green Deal: a quantitative textual analysis of the European Commission’s open online consultations,” International Groups & Advocacy 15 (2026): 101–131. https://doi.org/10.1057/s41309-025-00253-x 11 EUR-Lex statistics on legislative output: https://eur-lex.europa.eu/statistics/legislative-acts-statistics.html. For analysis of regulatory volume growth see European Parliament Research Service, “The volume and cost of EU legislation,” EPRS, 2023; and Igan, D. et al., “Regulatory complexity and growth,” IMF Working Paper 2024. The specific word-count figures in the text are drawn from a cross-source analysis of EUR-Lex annual publication data. 12 Sgaravatti, G., Tagliapietra, S. and Zachmann, G., “Germany’s gas price defence shield: problems and redeeming features,” Bruegel Blog, 2022. https://www.bruegel.org/blog-post/germanys-gas-price-defenceshield-problems-and-redeeming-features

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On French nuclear constraints: Commission Regulation (EU) No 2019/943; on the ARENH scheme limiting EDF, see: Loi n° 2010-1488 du 7 décembre 2010, France. On the political economy of nuclear exclusion from EU taxonomy and renewable support frameworks: Sgaravatti, G. and Tagliapietra, S., “EU taxonomy and the nuclear question,” Bruegel Policy Contribution, 2022; Bocse, A.-M. and Overland, I., “EU energy policy and the nuclear question,” Energy Research & Social Science 91 (2022). On Germany’s influence on European nuclear policy: Kemfert, C. and Traber, T., “German nuclear phase-out: regional and temporal effects on electricity generation, CO2 emissions and electricity prices in Europe,” DIW Discussion Paper, 2014. 14 Hartley, Peter, “Energy Demand and Electrification,” in Energy Insights 2025 (Baker Institute for Public Policy, Rice University, 2025). https://issuu.com/mh183/docs/energy_insights_2025/11 15 ACER, “Opinion on the bidding zone review,” ACER, 2022; Bundesnetzagentur decisions on Germany–Austria price zone split, 2018. 16 IEA, “World Energy Outlook 2024,” IEA, October 2024, pp. 72–89 (grid congestion and system integration challenges). Industry perspective: Carlyle Group, “The New Joule Order,” Carlyle, March 2025. https://www.carlyle.com/sites/default/files/2025-03/Carlyle_The_New_Joule_Order.pdf. The quotation reflects market-practitioner assessment; the underlying analytical finding on grid bottlenecks and underinvestment in dispatchable capacity is corroborated by IEA and ENTSO-E grid adequacy assessments. 17 Oxford Economics, “Claims of deindustrialisation in Europe are overblown,” Oxford Economics, 2024. https://www.oxfordeconomics.com/resource/claims-of-deindustrialisation-in-europe-are-overblown/; BP Statistical Review of World Energy 2023. 18 European Commission, “Proposal for a Regulation on Critical Raw Materials,” COM/2023/160 final, March 2023. The impact assessment documents EU import dependency: 98% of rare earth elements sourced from China; lithium predominantly from Chile and China; cobalt from the DRC. See also IEA, “Critical Minerals Market Review 2024,” IEA, 2024. https://www.iea.org/reports/critical-minerals-market-review-2024 19 European Commission / JRC EDGAR database, “GHG Emissions of All World Countries, 2024 Report,” 2024. https://edgar.jrc.ec.europa.eu/report_2024 20 European Central Bank, “The impact of energy price shocks on corporate investment in the euro area,” ECB Economic Bulletin, Issue 8/2025. https://www.ecb.europa.eu/press/economicbulletin/articles/2025/html/ecb.ebart202408_01~1d16a30700.en.html 21 European Investment Bank, “EIB Investment Survey 2024,” EIB, 2024. https://www.eib.org/attachments/lucalli/20240238_econ_eibis_2024_eu_en.pdf 22 IEA, “Energy Prices and Taxes,” quarterly data series, Q3 2024 (IEA, Paris, 2024). Industrial electricity prices in the EU-27 averaged approximately EUR 150–180/MWh in 2023 versus approximately USD 70–85/MWh in the United States. See also: Eurostat, “Electricity prices for non-household consumers,” nrg_pc_205, 2024; McWilliams, B. and Zachmann, G., “European natural gas demand tracker,” Bruegel, 2024. 23 European Central Bank, “Euro area export performance: recent developments and drivers,” ECB Economic Bulletin, Issue 6/2024. https://www.ecb.europa.eu/press/economicbulletin/articles/2024/html/ecb.ebart202406_01~3639959dc2.en.html 24 Sgaravatti, G., Tagliapietra, S., Trasi, C. and Zachmann, G., “National fiscal policy responses to the energy crisis,” Bruegel Datasets, 2022 (updated). https://www.bruegel.org/dataset/national-policies-shieldconsumers-rising-energy-prices 25 Medlock, Kenneth B., “Energy Security and the Role of Markets,” in Energy Insights 2025 (Baker Institute for Public Policy, Rice University, 2025). https://issuu.com/mh183/docs/energy_insights_2025/11

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SUSTAINABILITY AND RESILIENCE

From Circularity to Resilience: Plastics as a Strategic Resource Rachel Meidl Fellow in Energy and Sustainability | CES Deputy Director

Introduction For decades, policies focused on plastics have largely been framed through the lens of waste, pollution, and recycling. Public discourse, debates, and sustainability initiatives have leaned heavily into reducing plastic consumption, increasing recycling rates, and mitigating environmental leakage. While these concerns are legitimate and deserve continued attention, they represent only part of a much larger and progressively consequential story. A convergence of geopolitical instability, supply chain disruptions, resource competition, technological transformation, and shifting economic priorities is reshaping the view of materials by governments and industries. Plastics are emerging not simply as consumer products or waste streams, but as strategic resources that underpin modern economies, critical infrastructure, and national resilience. The same material family that has become synonymous with environmental concern also enables healthcare delivery, food security, water security, energy systems, transportation, telecommunications, semiconductors, military and defense, and emerging technologies. Plastics are integral to solar panels, electric vehicles, batteries, data centers, medical devices, aerospace systems, and countless applications that support economic growth and societal well-being.

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From Circularity to Resilience: Plastics as a Strategic Resource

As nations seek to strengthen domestic manufacturing, secure critical supply chains, and reduce vulnerabilities to geopolitical disruptions, a broader question is beginning to emerge. Should plastics be viewed solely as a waste management challenge, or should they also be recognized as a strategic material requiring long-term stewardship? Answering this question requires moving beyond traditional circularity discussions and toward a more comprehensive framework centered on resilience.

The Hidden Infrastructure of Modern Society Ironically, the role of plastics in modern life is often overlooked precisely because of their ubiquity. Unlike critical minerals, semiconductors, or energy resources, plastics rarely appear in discussions of national security or strategic competitiveness. Yet virtually every sector of the economy depends on them. A few examples include Healthcare systems rely on plastics for sterile medical devices, pharmaceutical packaging, intravenous bags, personal protective equipment, laboratory equipment, and diagnostic technologies. Modern medicine would be unrecognizable without plastic materials. Energy systems depend on plastics. Wind turbine blades incorporate advanced polymer composites. Solar panels require polymer components that provide insulation, durability, and weather resistance. Electrical grids rely on plastic insulation for transmission and distribution infrastructure. Electric vehicles contain significant quantities of engineered polymers that reduce weight and improve efficiency. Plastics play a critical role in food and water systems. Food packaging helps reduce spoilage, extend shelf life, and improve the safe transport of food across global supply chains. In water systems, plastics are widely used in treatment facilities, distribution infrastructure, irrigation networks, and sanitation systems that support public health, agricultural productivity, and economic development. The digital economy is dependent on plastics. Data centers, telecommunications networks, consumer electronics, semiconductors, and artificial intelligence infrastructure all require sophisticated polymer materials. As AI deployment accelerates and demand for computing capacity grows, so does demand for the materials that enable those systems to function.

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More generally, sectors traditionally associated with metals, concrete, or fuels increasingly rely on plastics to improve performance, durability, safety, and efficiency. Yet, despite this reality, sustainability discussions often isolate plastics as an environmental problem while overlooking the essential societal functions they perform. Such framing creates a false dichotomy between sustainability and plastics when the more relevant challenge is how to manage plastic materials responsibly and efficiently throughout their life cycle.

Geopolitics, Supply Chains, and Material Security Recent geopolitical events have highlighted the fragility of global supply chains. The COVID19 pandemic, disruptions in the Red Sea, conflicts in Eastern Europe and the Middle East, and growing tensions among major economic powers have exposed vulnerabilities across critical industries. While the availability and price of crude oil, natural gas, and petroleum products have dominated much of the public discussion, there is also a growing discourse on electrification and the materials needed to drive it, including batteries, semiconductors, rare earths and critical minerals. Yet, absent from much of the conversation is the fact that all the above intersect at various points with the plastics value chain. The production of plastics depends heavily on a complex network of global production and trade of oil, natural gas, natural gas liquids, petrochemical intermediates, and manufactured resins that move through some of the world's most strategically important trade corridors. Disruptions at any point can create cascading impacts across industries that depend on those materials, highlighting the strategic significance of plastics as a material resource. Consider the Strait of Hormuz, through which roughly one-fifth of the world's petroleum and globally traded liquefied natural gas transit. Any disruption to this corridor has implications not only for fuel markets but also for petrochemical feedstocks that support plastics production. The resulting impacts cascade through a range of industries—from water management systems to aerospace to agriculture to consumer electronics to construction. Such events highlight the extent to which plastics are intertwined with global energy and material systems and reinforce the importance of developing more resilient, diversified supply chains.

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Historically, plastic waste was viewed primarily as a disposal challenge. However, plastic waste can also be a domestic resource. This perspective does not diminish the importance of waste prevention, reduction, reuse, or other strategies; rather, it acknowledges that materials that have already entered the economy retain value that can be recovered and reintegrated into productive use. End-of-life plastics represent a concentrated source of carbon and material value already present within regional borders. In a world characterized by resource competition and supply chain uncertainty, commercial recovery of that value can contribute to economic resilience, manufacturing competitiveness, and resource security. The conversation, therefore, extends beyond environmental objectives. As concerns about resource security, supply chain resilience, and manufacturing competitiveness continue to grow, circularity becomes not only an environmental aspiration but also as a strategic capability.1

Circularity as a Resilience Strategy Circular economy discussions have traditionally emphasized waste reduction, recycling, and environmental performance. While these outcomes are important, circularity also serves a broader purpose—retaining value within a system.2 When materials are discarded, landfilled, or lost to the environment, the embedded energy, labor, capital, and resources invested in those materials are also lost. Conversely, when materials are recovered, recycled, and reintegrated into productive use, a portion of that value remains available to support future economic activity. Viewed through this lens, circularity extends beyond environmental performance. By retaining material value, reducing dependence on virgin resource inputs, and creating additional pathways for material recovery, circular systems can strengthen supply chain resilience. A resilient system minimizes the impact of volatile external inputs by exploiting optionality through diversifying input pathways, inventory management, and redundancy, thereby ensuring access to inputs even during periods of disruption.3 For plastics, this means developing systems capable of recovering value from a broader range of material streams. Mechanical recycling, advanced recycling, reuse systems, improved collection infrastructure, and design innovations each play important and distinct roles. No single approach is sufficient. Rather, resilience emerges from a portfolio of complementary solutions that collectively expand the range of materials that can be recovered and returned to productive use.

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But a system-level perspective differs substantially from current and past policy approaches that prioritize a single technology, metric, or outcome. Resilience requires flexibility, adaptability, and recognition that different materials and applications demand different solutions.

Reframing the Sustainability Narrative Around Plastics The sustainability community is gradually recognizing the importance of system-level thinking, yet many policy frameworks continue to interpret environmental objectives as separate from economic and security considerations. This distinction is becoming more difficult to maintain. Energy security, resource security, supply chain resilience, economic competitiveness, and system-level sustainability are deeply interconnected. Decisions affecting one dimension often influence the others. Equally important are the social dimensions of sustainability, including public health, access to essential goods and services, workforce impacts, community well-being, and quality of life. A system-level approach recognizes that sustainability is achieved not by optimizing a single objective, but by balancing environmental stewardship, economic viability, and societal needs across interconnected systems.4 Plastics illustrate this reality particularly well. Current discussions often frame plastics and sustainability in opposition to one another. Yet this framing overlooks a fundamental reality: many of the technologies, products, and systems required to achieve broader sustainability objectives depend heavily on plastics. The challenge, therefore, is not whether society should use plastics; rather, it is how to manage the carbon and material value embodied within plastics more effectively across their life cycle. Sustainability lies not in impractical efforts to eliminate impacts altogether, but in minimizing risks while maintaining long-term economic viability to ensure the burdens and benefits of progress are shared rather than shifted. Inherent in this approach is that trade-offs are unavoidable and must be managed transparently and thoughtfully. Efforts to reduce environmental impacts must balance efforts to maintain healthcare needs, food and water security, transportation efficiency, energy infrastructure integrity, technological innovation, and broader social and economic development. Likewise, strategies focused exclusively on material security or industrial competitiveness must address environmental performance and public trust.

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Managing tradeoffs effectively across complex systems requires moving beyond simplistic narratives that categorize materials, technologies, or industries as intrinsically sustainable or unsustainable. Framing plastics as such oversimplifies a far more complex reality. The more productive question is how can society maximize the value plastics provide while minimizing the environmental, economic, and social impacts associated with their production, use, and end-of-life management?

Conclusion Once viewed primarily as a waste management issue, plastics are now intersecting with broader concerns about resource security, industrial competitiveness, supply chain resilience, and national preparedness. The environmental challenges associated with plastics are often less a function of the material itself than how it is produced, used, and managed across its life cycle. At the same time, plastics remain an essential material underpinning modern economies and supporting critical functions across healthcare, food and water security, energy infrastructure, manufacturing and digital technologies. This does not diminish the need to reduce waste, improve environmental performance, or prevent material leakage. Rather, it expands the conversation to include how policy, technology, markets, and society can preserve value, strengthen supply chain resilience, and improve resource productivity across the full life cycle of plastics. The next phase of sustainability will require a broader perspective—one that views circularity not merely as a waste reduction strategy but as a pathway toward greater resilience. After all, today’s geopolitical stress is emphasizing that the ability to secure strategic material supply chains is just as important as the ability to produce them in the first place.

Notes 1

Meidl, Rachel A., “Geopolitical Conflict Highlights Circular Carbon Pathways in Plastics,” Rice University's Baker Institute for Public Policy (May 18, 2026). DOI: 10.25613/Q2V6-9C77. 2 Meidl, Racel A., “Opening Schrödinger’s Box: Rethinking Carbon Beyond the Binary in Plastic Recycling,” Rice University's Baker Institute for Public Policy (May 7, 2026). DOI: 10.25613/NBWK-R230. 3 Medlock III, Kenneth B., “Energy Security and Supply Chain Resilience,” Energy Insights 2025, Center for Energy Studies, Baker Institute, Rice University, p.11-22. Energy Insights 2025 by Baker Institute Center for Energy Studies (CES). 4 Meidl, Rachel A. and Kenneth B. Medlock III, “The Pride and Prejudice of Sustainability: Rethinking Sustainability from a Systems Perspective,” Rice University's Baker Institute for Public Policy (Nov 8, 2023). DOI: 10.25613/20CH-3Z48.

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Beyond the Loop: Creating an Adaptive Circular Network for Plastics Jackie deGroot Nonresident Fellow

Introduction Nearly a decade since the Ellen MacArthur Foundation catalyzed a global value chain and policy movement toward a circular economy for plastics, the paradigms and infrastructure for extending plastics’ economic value while protecting natural resources are still under construction. Circularity so far has been built primarily around a single plastics-to-plastics loop — today’s mechanical recycling system. Yet the interconnectivity plastics have, or could have, across every sector of the economy offers far greater possibility. We are at a transition point: how we define the next-generation framework for plastics circularity will determine whether this moment becomes transformational or simply a stretched version of the system that already exists.

An Argument for Moving From a Linear to a Circular Plastics Economy Stepping into the 21st century, society experienced an awakening to plastics in the environment. Studies over the following decade-and-a-half quantified the environmental impact of plastic land and marine debris. The problem that surfaced was pollution, but the problem the world rallied behind was what the World Economic Forum (WEF) and Ellen MacArthur Foundation (EMF) termed a plastics economic systems problem.1

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These organizations argued that the linear “take, make, dispose” model was flawed because plastics retain most of their value well beyond initial use — landfilling and incineration negate that value while creating downstream environmental issues. They proposed a circular economy model built on three principles: design products and systems to 1. reduce plastic waste and pollution, 2. circulate plastics at their highest value (reuse, repair, recycle), and 3. regenerate nature. They argued this was economically achievable with the right policies, infrastructure, and business models. The concept took hold with business leaders. In 2018, EMF published The New Plastics Economy Global Commitments, signed by over 250 organizations including major consumer brands, who publicly committed to reduce virgin plastics, design for reusability and recyclability, and incorporate recycled content through self-defined 2025 targets. Notably, brand owners made these commitments without a clear roadmap. But as channel captains of the industry, they created the suction for a collaborative effort across the global plastics value chain. In parallel, NGOs, regulators, and policymakers began drafting local and regional policies to lock in industry commitments to help fund the infrastructure and systems circularity would require.

A Decade of Innovation Material Innovation: Resin producers, package producers, equipment manufacturers, and brands saw the shift as both opportunity and existential threat. Materials scientists developed new and modified polymers, fabrication equipment, and packaging formats to meet the mono-material specifications mechanical recycling requires — stretching polyethylene (PE) to perform some roles once reserved for PET or nylon. These stiffer, tougher, higher-barrier PE grades also enabled lightweighting in mono-material packages, reducing plastic use altogether and creating circularity benefits beyond their original intent. In parallel, polymer scientists worked to make dissimilar materials compatible so strict mono-material construction was no longer always necessary for mechanical recyclability at scale—breaking through a prior barrier.

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This catalyzed further innovation in optical sortation, AI, and polymer identification, letting material recovery facilities (MRFs) distinguish subtler differences among plastic packages (polymer type, color, format) and produce cleaner, more homogeneous streams that access higher-value end markets. This area continues to be ripe for innovation. Process Innovation: Process scientists, meanwhile, targeted mechanical recycling’s traditional limits: its inability to process multi-material, multi-layered, film, and flexible packaging, and the limits of conventional cleaning and purification. They developed—and revived—what are now called advanced recycling processes, breaking a broader range of plastic waste down to molecular components to form new feedstocks with virgin-like quality and consistency. This diverts more plastic from waste streams, displaces some fossil fuel feedstocks, and expands the applications—including contact-sensitive uses like food and pharma—that can incorporate recycled content. Advanced recycling also links to other industries by producing other by-products such as fuels and feedstocks for petrochemical and energy supply chains. Regulatory and Policy Innovation: Meanwhile, waste haulers, sorters, MRFs, mechanical recyclers, NGOs, and policymakers steadily refined the definitions, methods, and systems for collecting, sorting, and accounting for mechanically recycled waste—the model for state and national Extended Producer Responsibility (EPR) laws. EPR is the mechanism meant to make circularity economically viable: it lets producers, primarily brands, retailers, and ultimately consumers share the cost of managing plastic waste through fees based on packaging material and format, while mandating recycled content to create steady demand. Eco-modulation fees are set to begin in four US states during 2026 and 2027. Both sides saw opportunity to innovate—industry around technologies and networks; regulators around funding models and definitions. Both moved circularity forward, but not necessarily toward the same destination.

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Progress and Tension in the Next Phase of Circularity EMF’s latest report, which analyzed 2024 performance against signatories’ commitments, shows real progress. Packages designed for recyclability rose from a 2018 baseline of 65– 70% to 90% (against a 100% goal by 2025), while actual recycled content incorporation rose from 4.8% to 14% (against a 25–26% goal). Brands argue that even short of their targets, the voluntary effort was massive, but they point to two persistent barriers: Lack of suitable recycling infrastructure, particularly for film and flexibles. Insufficient high-quality post-consumer recycled (PCR) plastic, especially for food and contact-sensitive applications. Advanced recycling was meant to ease both, but inconsistent global, federal, and state definitions have stalled that pathway. Still, US EPR laws push for recycled-content mandates well above the original EMF commitments. For example, California’s SB54 sets 30%, 40%, and 65% targets for single-use packaging and food-service utensils by 2028, 2030, and 2032. This tension has moved into the courts. ExxonMobil is being sued by the People of the State of California for allegedly deceptive marketing tied to advanced recycling and mass-balance attribution, fueling public distrust. Separately, seventeen Republican state attorneys general sued in the U.S. District Court for the Eastern District of California on June 29, 2026, arguing California’s SB54 is unconstitutional for imposing “substantial burdens on interstate commerce.” Investment is wavering, too. Nearly half of announced advanced recycling capacity in the US and Europe has been paused or shut down in recent years. Meanwhile, oversupply of lowcost virgin plastic from Asia has pushed prices and profits down industry-wide, widening the gap between virgin and recycled plastics pricing. This is made worse in Europe by high energy costs.

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What We Lose if We Can’t Move Beyond the Loop The US is at a crossroads, with two sides forming rather than one cooperative effort. One envisions growing plastics circularity—and the industry itself—in a more environmentally responsible, economically viable, and interconnected way. The other wants a more tightly controlled system with less plastic use overall, higher plastic-to-plastic recycling, and higher recycled content in packaging. Neither goal looks achievable within the closed, mechanicalrecycling loop defined to date, so the framework itself needs to change. Waiting for lawsuits to settle, or for one side to concede, risks losing the momentum and collaboration built so far. Progress made together, and the stable long-term markets EPR schemes can create will outperform what either industry or policy can achieve alone.

Framework and Criteria for a More Adaptive, Circular Economy A new framework should start from the same shared vision that got us here. This rests in the core principles of a plastics circular economy: design products and systems to reduce plastic waste and pollution, circulate plastics at their highest value, and regenerate nature. All this can be made economically viable through the right policies, infrastructure, and business models. To enable stable end markets and resilient supply chains, an overarching national EPR framework is needed to prevent over-complication and supply chain constraints across jurisdictions. This would include consistent definitions for key concepts like circularity, recyclability, recycle rate, recycle content, reusability, recovery as well as what constitutes a producer and a recycler. The framework would also set standards and allow each region to determine implementation and fees based on local resources and infrastructure. With these elements in place, an adaptive, dynamic network of interconnected circularity systems can grow, delivering economic, environmental, and societal benefits beyond what today’s boundaries allow. Criteria for incorporating new systems into this framework should be technology-neutral and performance-driven and could include elements outlined in Table 1.

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Table 1 — Elements for a New Framework Circularity Aspects Core Circularity Principles Optimized

What are the natural resource impacts (land, air, water, virgin fossil fuels, water, and other resources displaced or conserved) across the life cycle? What are the GHG emissions / avoided emissions across the life cycle?

Network InterConnectivity

What effect will this have on other loops within the overall circularity system? Infrastructure and Tools to Support the Systems / Loops

Definable Design for Circularity Criteria

What product design/bale criteria are necessary for the recovery system's success? Any impact on new package designs or other circular pathways?

Collection and Sortation Can it be collected at scale? Can it be sorted and channeled to Demonstration the right loop? Available Commercial Scale Infrastructure

Is there sufficient available capacity to process at scale for a defined jurisdiction?

Verification and Traceability

Can the claimed circular outcome be independently measured and audited? Yields / Efficiencies

Rate of Efficiency for Collection / Sortation / Manufacturing

Can the process generate yields sufficient to sustain it economically?

Recycle / Recovery Rates

What percentage of collected material becomes recycled material or feedstock for plastics? What portion becomes feedstock for other products or fuel? What portion becomes residual waste? Economics

System Cost

What cost does the package impose on collection, sorting, processing, and disposal systems?

Sponsoring End Markets Are there valued, stable end markets where this material can for Recycled / compete? Recovered Material Economic Viability

Can the process operate sustainably at commercial scale without continual subsidy? 243

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What To Watch For This next phase of plastics circularity will not be defined by one technology replacing another, but by integrating multiple recycling and recovery pathways into an adaptive, measurable, and resilient system. Signposts include: A federal EPA decision on what constitutes recycling versus waste disposal via incineration or waste-to-energy processes, and how advanced recycling facilities are regulated and permitted Consistency among state EPR laws through an overarching national body that sets clear definitions and standards for the US as a whole Technology-neutral national circularity standards that apply to mechanical, physical, chemical, and biological recycling alike, focused on the core circularity principles Close collaboration among science, industry, and policy stakeholders in that national body, to keep standards and metrics scientifically grounded and consistently applied Simplified standards for mass balance accounting and certification systems that build public trust and accountability around national metrics Transparent reporting of producer performance against simplified national metrics Better communication and education clarifying the roles of governments, industry, and consumers in a circular economy Clear pathways from regulatory bodies like the Association of Plastics Recyclers for introducing new loops within the circularity system, plus Circular Design Guides, bale specifications, and certification for the new loops EPR timelines ambitious enough to drive progress but realistic with respect to infrastructure build-out EPR laws that create long-term demand by crediting producers for incorporating recycled content—narrowing the virgin-recycled price gap and stimulating investment in this growing sector of the economy The last decade proved both the opportunity and the capability to move beyond where we are today. Inclusive thinking about how to achieve circularity’s core principles across every industry sector using a variety of valid pathways is what will turn this into a truly transformational effort.

Notes 1

World Economic Forum, Ellen MacArthur Foundation and McKinsey & Company. (2016). The New Plastics Economy: Rethinking the future of plastics. Geneva: World Economic Forum.

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An Enduring Emphasis on Resilience ‘Run It Back’ from Energy Insights 2025

Kenneth B. Medlock III CES Senior Director | James A. Baker, III and Susan G. Baker Fellow in Energy and Resource Economics

Miaomiao Rimmer CES Research Manager

Article Preface: A Context for Current Policy Discussions Resilience is a concept that runs through a broad spectrum of energy and environmental issues. At its simplest, resilience is the ability of a system—market, environment, ecosystem, etc.—to recover from an unexpected change. In the wake of the closure of the Strait of Hormuz, resilience has been a central theme in understanding how markets, and the supply chains that run through them, respond and adapt. In the context of natural disasters, resilience is often framed around how populations recover from the damages absorbed. It is multidimensional, and it looks different everywhere.

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Despite the potential difficulties in identifying how to achieve resilient systems, there are important factors that can help drive successful outcomes. Generally, this requires a recognition that resilience requires thinking about avoiding risks as well as insuring against their impacts. In the context of climate change and extreme weather, adaptation is gaining traction as a path that recognizes trade-offs and lends to societal resilience.1 Interestingly, this is no different than steps taken by commercial actors along a market supply chain—i.e., assess the risks of disruption, evaluate the respective costs of abating the risks or dealing with their consequences, then take action to minimize overall costs. Risk analysis requires accurate information and data so that appropriate probabilities can be assigned to outcomes and an expected cost can be assessed.

Perception, Reality, and Where the Two Shall Meet A typical refrain in discussions about the damages of climate change holds that the frequency of extreme weather events and wildfires seems to be increasing. But data and discourse can sometimes diverge. Take, for example, hurricanes, tropical storms, and other tropical disturbances. In the decade of the 1950s, there were 59 such events, with six major hurricanes (three Category 3 and three Category 4 storms; a major hurricane is anything in the Category 3–5 range). In the 2010s, there were 65 such events, with four major hurricanes (all of which were Category 4 storms). Hence, there were a greater number of overall tropical events, but fewer major hurricanes. This begs a question that is often debated with very little constructive outcome: What is perception, and what is reality? Since the 1950s, media coverage of natural disaster events has grown exponentially, as indicated in Figure 1. The number of stories has increased rapidly. The number of deaths and financial costs of damages has also increased, but to the same extent as media coverage. Moreover, the number of natural disasters has not followed the same trends. Nevertheless, the proliferation of media coverage that runs during and after a natural disaster (and even prior to, in the case of tropical disturbances) is undeniable, and it can shape perceptions about frequency and intensity. Of course, the drivers of the trends in Figure 1 are numerous — the expansion of the number of media outlets, the emergence of 24/7 news coverage, the proliferation of handheld devices that can livestream media, urban expansion that carries a growing market segment, revealed consumer preference for specific types of news stories, and more — but exploring what drives exponential growth in media coverage is not constructive for the matter at hand. 247

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Figure 1 — US Media Coverage of Natural Disasters by Decade

Source: Data was generated using Perplexity, with a keyword search on natural disasters as defined by the National Oceanic and Atmospheric Administration (NOAA), as shown in the figure key. Note: For the purposes of illustration, Winter Storm/Freeze is the sum of Winter Storms and Freezes, while Severe Storms/Flooding is the sum of Severe Storms and Flooding. The asterisk indicates that 2020–2029 only includes data through 2024.

Why? Because there are pathways that offer solutions to mitigating, and even avoiding, the damages from natural disasters. Yet, discussions are not fully exploring the portfolio of options available. Understanding the entirety and breadth of the data underneath this dilemma is critical for policy to directly address concerns, real or not. When data collection and reporting methodologies change, a structural break in the underlying data series is present.2 While technical exploration of the implications of structural breaks in data is important and should be a central part of understanding the optimal portfolio for damage mitigation, it has no bearing on what is in the portfolio. To be clear, the frequency of natural disasters fluctuates, and data collection and reporting techniques has changed over time. Figure 2 indicates tropical cyclones and disturbances tracked by the National Oceanic and Atmospheric Administration (NOAA) by decade since the 1950s, ordered from most to least intense.3

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The number of major hurricanes, which are classified on the Saffir-Simpson Scale as Category 3, 4, and 5, did not change much from the 1950s through the 2010s, although the number of tropical storms and other tropical disturbances shows much greater fluctuation. The first half of the 2020s, however, does indicate an uptick in major storms, but the final numbers for the decade are still not in, and there is substantial variation from year-to-year (not pictured) in the historical record. Figure 3 indicates the dramatic shift in reporting that occurred in 1996 and resulted in a dramatic increase in the types of events being tracked and reported, moving from three through 1995, with a significant step change in 1996, and expanding to more than 50 event types today.4

Figure 2 — US Tropical Cyclones by Decade, 1950s–2020s

Source: International Best Track Archive for Climate Stewardship (IBTrACS) and National Centers for Environmental Information (NCEI). Note: The asterisks indicates that 2020–2029 only includes data through 2024.

Moreover, some of those reported events overlap with a single weather system. For example, hail and tornadoes that occur in a single severe storm, or marine tropical storms that become hurricanes that make landfall, all register as unique events. So, as the number of events tracked has expanded, it should be no surprise that the number of events reported has expanded.

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Figure 3 — The Recent Evolution of the NOAA Storms Database, 1980–2024

Source: NCEI, Storm Events Database. Note: As noted at the site, “the database currently contains data from January 1950 to May 2025, as entered by NOAA’s National Weather Service (NWS). Due to changes in the data collection and processing procedures over time, there are unique periods of record available depending on the event type. NCEI has performed data reformatting and standardization of event types but has not changed any data values for locations, fatalities, injuries, damage, narratives, and any other event-specific information.”

Fortunately, the entire focus need not be on the number of events; rather, damages are the issue. According to the National Centers for Environmental Information (NCEI) at NOAA, from 1980 to 2024 the United States recorded 403 events that each caused at least $1 billion in damages (Figure 4).5 It should be noted, however, that the reported data only indicate events that cost at least $1 billion at the time they happened. Then, they are inflation adjusted. This biases the reported data in earlier time periods and exacerbates the apparent trend. For example, a $265 million storm in 1980, when inflation adjusted to 2024, is a $1 billion storm, but this is not accounted for in Figure 4. Efforts were underway to correct this, but currently, data collection and reporting have been suspended.6 Nevertheless, the presentation of the data in Figure 4 conveys a causal relationship between natural disaster frequency and financial damages.

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Figure 4 — US Billion-Dollar Disaster Events, 1980–2024

Source: NOAA, Billion-Dollar Weather and Climate Disasters, Time Series; and NCEI. Note: Monetary amounts are adjusted per the consumer price index.

However, in the case of hurricanes (e.g., labeled as tropical cyclones in Figure 4), a key focus area of research has been on distinguishing between meteorological and societal drivers of hurricane damage, with peer-reviewed research indicating that damage is largely driven by population growth and property value appreciation, rather than increasing frequency or intensity of hurricanes.7 Other peer-reviewed research has investigated the drivers of hurricane frequency and intensity with varied outcomes.8 Suffice it to say, things are not as simple as sometimes portrayed. That stated, in terms of mitigating damages, is this even a relevant discussion?

What About Adaptive Resilience? Admittedly, this can be a contentious topic. But as we navigate the perils of debating what the data indicate and what the future may hold, it remains apparent that something needs to be done to address damages, regardless. To that end, if the focus on dealing with damages associated with natural disasters is addressed through a lens of social efficiency, then the concept of resilience comes into view. 251

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Social efficiency is typically defined where the marginal cost of damages of an externality (i.e., in the case of climate, the driver of the externality is greenhouse gas emissions) is balanced with the marginal cost of abating the damages. Abating damages can include, of course, reducing the driver of the externality, but it can also include reducing the impacts of disaster events. Of course, attribution of damages to the externality versus other drivers matters, but if the full portfolio of options to abate damages is internalized, policy discourse can be much more constructive (pun intended). Resilience matters. Framing risks associated with natural disasters as an insurance problem allows us to see solutions in a different light. Typically, if the expected losses from an incident exceed the costs incurred to insure against those losses, then the entity bearing the burden of the costs is underinsured.9 A key word here is “expected,” because it indicates a need for assessments of the probability of an incident occurring (i.e., risk) as well as the cost of the incident. If the probability of an incident occurring increases, then, for a given cost, the optimal amount of insurance coverage should increase. Similarly, if the cost of an incident increases for a given probability of that incident occurring, then the optimal amount of insurance coverage should increase. In either case, the insurance coverage should increase. Applying this to the case of natural disasters can be informative. If a region has historically been prone to tropical storms and hurricanes (or wildfires, or floods, or tornadoes) and real estate development in the region expands, then the probability of property damage occurring increases, even if the probability of a natural disaster does not increase, precisely because there is now more property in the affected region. This is akin to shooting arrows at a target while making the bull’s-eye larger; the probability of hitting the bull’s-eye rises with each subsequent shot. Optimal insurance coverage, and hence insurance premiums, should rise for every property in that risk pool, unless there is a policy intervention that prevents it. Similarly, if the replacement cost of property in the affected region increases, which would certainly be the case when property values appreciate with urban expansion, then the optimal insurance coverage, and hence insurance premiums, will be higher. So, both the probability of a loss and the replacement cost matter. The dashboard includes interactive layers for hurricane and tropical storm tracks, tornadoes, floods, fire perimeters, county population density, and urban tracts since 1950, as well as various energy infrastructures. Users can explore different temporal combinations of demographics and disasters to see how hazards and growth patterns have evolved.

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Overlaying hazard layers with demographic and infrastructure layers allows users to see where high‑risk events coincide with dense populations or critical assets. For example, the hurricane layer shows how storm tracks overlap with expanding populations and urban tracts over time; the fire perimeter layer highlights how wildfires align with expanding urban tracts; and more.

Case Study 1: California Wildfires and the Wildland‑Urban Interface Consider the case of wildfires and the wildland-urban interface (WUI), as reported by the U.S. Department of Agriculture.11 The WUI increased significantly from 1990 through 2020, exposing a larger number of housing units to wildfire damages.12 In fact, the number and share of housing units in the WUI has increased across the U.S., with some states seeing greater expansion than others (Figure 5).13 California has the greatest number of housing units in the WUI, and its growth has been especially pronounced in certain regions, far exceeding national trends. From 1990 to 2020, the U.S. experienced a 31% increase in WUI area and a 47% rise in housing units.14 Over that same period, several California counties saw much steeper growth. In San Joaquin County, WUI housing surged by 611.6%; Stanislaus County increased by 246.4%; Orange County grew by 99.1%; and Riverside County by 74.1%. In 2020, California had approximately 5.1 million housing units in the WUI nationwide. The next closest state is Texas, at just over 3.1 million, followed by Florida at 2.6 million. In California, the expansion of housing in the WUI presents challenges for resilient communities, especially given the history of wildfires in the region (Figure 6).15 California has implemented several policies aimed at managing real estate development in WUI, though outright bans are rare. For example, the California Wildland‑Urban Interface Code (CWUIC) was first applied in 2008 and later expanded through Title 24’s Chapter 7A. The CWUIC mandates that any new structure in ”very high fire hazard severity zones” or designated WUI areas must comply with defensible space requirements, ignition-resistant materials, and ember-resistant design (roofing, vents, windows, etc.) before final building permit approvals. Compliance with vegetation management is also required prior to permit issuance.16 All of these are examples of insurance, which were discussed previously.

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Figure 5 — Housing Units and the Wildland-Urban Interface by State, 2020

Source: U.S. Department of Agriculture, “The Wildland-Urban Interface.”

Figure 6 — Southern California Wildfires and Urban Expansion Population and Urban Tracts in 2020 on Wildfires in the 1950s

Population and Urban Tracts in 1950 on Wildfires in the 1950s

Source: Center for Energy Studies (CES), “Dashboard: Natural Disaster Resilience.”

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While CWUIC improved the resilience of individual houses, state officials recognized that catastrophic wildfire losses represent a community-wide challenge rather than merely an issue at the individual structure level. Consequently, California officials concluded that a more comprehensive approach was needed, leading the California Building Standards Commission (CBSC) to adopt the 2024 International Wildland-Urban Interface Code (IWUIC). This updated code not only continues to enhance the protection of individual homes but also addresses the surrounding environment and community infrastructure, establishing a multi-layered system of wildfire defense.17 Despite recent policy advancements, California continues to face major hurdles in addressing wildfire risk in the WUI. Current building codes largely apply to new construction, but this leaves millions of older homes vulnerable without mandated upgrades. Although the state’s adoption of a more comprehensive, community-scale code marks an important shift, its effective implementation is constrained by substantial practical challenges. Enforcing broader requirements — such as vegetation management, emergency access, and adequate water supply — demands consistent funding, sufficient inspection capacity, and strong public participation. For many local jurisdictions, these needs present ongoing logistical and financial barriers that hinder the full realization of wildfire resilience goals.

Case Study 2: Tropical Weather and the US Gulf Coast Rapid urban expansion and population growth has been a defining feature of the U.S. Gulf Coast, especially Florida and Texas, over the last 50 years. However, in many places, this rapid development has outpaced resilience in land-use planning. For example, recent research indicates that over one fifth of housing units in Harris County, Texas lie within floodways, the 100‑year floodplain, or the 500‑year floodplain, and more than half a million residents live in affected neighborhoods. Moreover, these neighborhoods often have higher poverty rates and less capacity to recover from natural disasters.18 The devastation of Hurricane Harvey in 2017 revealed significant shortcomings in floodplain management and construction practices. The Greater Houston metropolitan region has significantly expanded into historical sugarcane and rice farming regions west and southwest of the city since the 1970s. This urban expansion can have ramifications for floodplain management. Since 2017, Harris County has strengthened its floodplain ordinance, mandating that all construction projects within the 100-year floodplain obtain permits and be elevated two feet above the 500-year floodplain to reduce flood risk.19 255

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Harris County also has several programs in place to assist residents whose properties are in flood zones, including both voluntary and, in certain areas, mandatory buyouts.20 In addition to local reforms, the Texas Industrialized Building Code Council adopted the 2021 International Building and Residential Codes and others as well as the 2020 National Electrical Code for industrialized housing and buildings, effective July 1, 2024. These updates represent a statewide step toward safer construction.21 Reinforcing this shift, Federal Emergency Management Agency’s (FEMA) “Building Codes Save” study demonstrates that the adoption of modern building codes significantly reduces losses from predictable natural hazards.22 However, delays in updated flood mapping hamper policy response, regulatory clarity, and insurance determinations for affected residents.23 The widespread flood damages related to Hurricane Harvey are not unique to hurricane events, but they do highlight a consistent weather risk in the U.S. Gulf Coast. For example, the trajectories and wind roses for Hurricanes Milton (2024), Ian (2022), Nicole (2022), and Alex (2022) are indicated in Figure 7, overlaid with Florida’s population and urban tracts in 2020 and 1950. The comparison reveals a striking alignment between the hurricane paths and regions of intensified urbanization. These areas, which were sparsely populated in 1950, have since undergone substantial demographic transformation, evolving into major urban corridors. As Florida’s population surged into high-risk coastal zones, the need for resilient infrastructure became undeniable — a lesson harshly reinforced by Hurricane Andrew in 1992, which exposed long-standing deficiencies in the state’s construction standards. In response, the state implemented the Florida Building Code (FBC) in 2001, one of the most rigorous codes in the country.24 A study by Kevin M. Simmons et al. found that homes in Florida built after 2000 experience 47–72% less in losses than homes built before 2000.25 While the FBC added an average cost of $3,254 to new homes, these homes experienced $10,093 less in damage within 10 years, meaning $3.10 is saved for every $1 invested in adhering to the FBC. So, the investment pays for itself just over eight years through reduced damage and lower insurance premiums.26 Resilience matters. But, despite the demonstrated cost-effectiveness of increased resilience standards, Florida still faces significant ongoing challenges in mitigating damages associated with hurricane risks, primarily due to a large number of older homes. Approximately 65% of occupied housing units were built before the stringent 2001 code was enacted.27 Energy Insights 2026

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Figure 7 — Selected Hurricanes and Urban Expansion in Florida Select hurricanes, 2021-2024 Population and Urban Tracts, 2020

Select hurricanes, 2021-2024 Population and Urban Tracts, 1950

Source: Center for Energy Studies (CES), “Dashboard: Natural Disaster Resilience.”

While retrofitting these properties to bring them in-line with current standards would help, the costs can be prohibitively expensive for many homeowners, creating a gap in resilience between new and existing communities.

Conclusion Why focus on resilience? Because disasters will not stop happening if greenhouse gas emissions drop to zero. So, the benefits of investments in resilience today will pay dividends down the road, especially if natural disasters increase in frequency and severity in the future. Population growth, urban expansion, the resulting alteration of landscapes, and increased penetration of the WUI will change floodplains and water flow from rainfall and increase exposure risks to wildfires. This can be very problematic when it occurs in regions that experience dry seasons, hurricanes, intense rainfall, and more. Vulnerability can be particularly high where building codes are insufficient. The increasing human and financial toll of natural disasters underscores the need to rethink where and how we grow. 257

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To be clear, this does not necessarily mean that we do not build, but land‑use decisions that allow development in high‑risk areas — such as flood‑prone coastal plains, river floodplains, and wildfire‑prone interfaces — compound risks. Resilience must therefore be integrated into urban planning and building codes and standards. It is imprudent to misrepresent or misprice damage risks (for example, through federal insurance programs that carry a classic moral hazard leading to underinvestment in risk mitigation), even if urban expansion is desired.28 It is not prudent to place all eggs in one basket. Fortunately, the full portfolio to reduce damages associated with the externality of greenhouse gas emissions is large. A lack of focus on resilience in the built environment and how it connects to the natural environment creates a devil of our own making, one that climate change can exacerbate. A hyperfocus on eliminating hydrocarbon fuels from the energy mix can ignore other pathways that could save lives, property, and billions of dollars. Moreover, this should not be political. Decades of data and analysis point the way. Using the damages from natural disaster to make a political point or to advocate for a single position is meaningless. To be clear, there are solutions, and everything must be on the table. Disasters are local. Climate is global. The evolving landscape of natural disasters is shaped by where and how we build as much as it is shaped by hazard frequency. While local and state efforts — such as stronger building codes and hazard-specific regulations — have improved resilience, their impact remains uneven due to enforcement gaps, aging infrastructure, and persistent social inequities. The insights gleaned from data visualization with a temporal overlay, like those addressed above, are not merely academic. They can inform policies that guide resilient infrastructure investments and inform broader debates about insurance and risk at the national, regional, and community levels. Long-term resilience hinges on integrating environmental realities into urban policy, ensuring that future urban development mitigates, rather than exacerbates, disaster risk.

Notes 1

See, for example, Hartley, Peter R., “The entanglement of climate and energy policies,” The Energy Journal, vol. 47, iss. 1, (2025): 261-286, https://doi.org/10.1177/01956574251375436. 2 Statisticians and econometricians have long known this cannot be ignored and have explored techniques for identifying and dealing with structural breaks. For a discussion of this topic, see Alexander Aue and Lajos Horváth, “Structural Breaks in Time Series,” Journal of Time Series Analysis 34, no. 1 (2013): 1–16, https://doi.org/10.1111/j.1467-9892.2012.00819.x. 3 National Centers for Environmental Information (NCEI), “International Best Track Archive for Climate Stewardship (IBTrACS),” National Oceanic and Atmospheric Administration (NOAA), accessed September 2025, https://www.ncei.noaa.gov/products/international-best-track-archive. 4 NCEI, “Storm Events Database,” NOAA, accessed September 2025, https://www.ncei.noaa.gov/stormevents/.

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NCEI, “U.S. Billion-Dollar Weather and Climate Disasters, 1980 – Present,” NOAA, last modified May 12, 2025, https://www.ncei.noaa.gov/access/metadata/landing-page/bin/iso?id=gov.noaa.nodc:0209268; NCEI, “BillionDollar Weather and Climate Disasters: Time Series,” NOAA, accessed September 2025, https://www.ncei.noaa.gov/access/billions/time-series/US/cost. 6 As reported on the NOAA’s website: “The U.S. sustained 403 weather and climate disasters from 1980–2024 where overall damages/costs reached or exceeded $1 billion (including CPI adjustment to 2024)” (NCEI, “Billion-Dollar Weather and Climate Disasters: Overview,” NOAA, accessed September 2025, https://www.ncei.noaa.gov/access/billions/time-series/US/cost). In addition, the site previously reported: “More recent feedback from the American Meteorological Society community have suggested that we incorporate smaller cost thresholds into our analysis, to more completely capture the hazard risk space. We are currently developing this more comprehensive scope, by quantifying the total, direct losses for all subbillion events down to $100 million, from 1980–present. We aim to provide new summary analysis for hundreds of events in late-April 2025, which will more completely describe the weather and climate event frequency and cost distribution over space, time and by hazard.” However, the latest update indicates: “In alignment with evolving priorities, statutory mandates, and staffing changes, NOAA’s National Centers for Environmental Information (NCEI) will no longer be updating the Billion Dollar Weather and Climate Disasters product” (NCEI, “Billion-Dollar Weather and Climate Disasters: Overview”). 7 Philip J. Klotzbach et al., “Continental U.S. Hurricane Landfall Frequency and Associated Damage: Observations and Future Risks,” Bulletin of the American Meteorological Society 99, no. 7 (2018): 1359–76, https://doi.org/10.1175/BAMS-D-17-0184.1; Jessica Weinkle et al., “Normalized Hurricane Damage in the Continental United States 1900–2017,” Nature Sustainability 1 (2018): 808–13, https://doi.org/10.1038/s41893-018-0165-2. 8 The following list is far from complete, but it provides decent exposure to the topics raised. The depth of literature on the topic is evidence enough of research interest. See, for example, Gabriel A. Vecchi et al., “Changes in Atlantic Major Hurricane Frequency Since the Late-19th Century,” Nature Communications 12 (2021): 4045, https://doi.org/10.1038/s41467-021-24268-5; Karthik Balaguru et al., “Increased U.S. Coastal Hurricane Risk Under Climate Change,” Science Advances 9, no. 14 (2023): eadf0259, https://doi.org/10.1126/sciadv.adf0259; J. B. Elsner et al., “Fluctuation in North Atlantic Hurricane Frequency,” Journal of Climate 12, no. 2 (1999): 427–37, https://doi.org/10.1175/15200442(1999)012<0427:FINAHF>2.0.CO;2; Kerry A. Emanuel, “The Dependence of Hurricane Intensity on Climate,” Nature 326 (April 1987): 483–5, https://doi.org/10.1038/326483a0; Morris A Bender et al., “Modeled Impact of Anthropogenic Warming on the Frequency of Intense Atlantic Hurricanes,” Science 327, no. 5964 (2010): 454–8, https://www.science.org/doi/10.1126/science.1180568; Greg Holland and Cindy L. Bruyère, “Recent Intense Hurricane Response to Global Climate Change,” Climate Dynamics 42 (March 2013): 617–27, https://doi.org/10.1007/s00382-013-1713-0; and T.N. Krishnamurti et al., “The Hurricane Intensity Issue,” Monthly Weather Review 133, no. 7 (2005): 1886–1912, https://doi.org/10.1175/mwr2954.1. 9 For a seminal discussion of these concepts, see Vernon L. Smith, “Optimal Insurance Coverage,” Journal of Political Economy 76, no. 1 (1968): 68–77, https://doi.org/10.1086/259382. 10 Center for Energy Studies (CES), “Dashboard: Natural Disaster Resiliency,” Rice University’s Baker Institute for Public Policy, accessed September 2025, https://www.bakerinstitute.org/dashboard-natural-disasterresilience. 11 According to an article by V.C. Radeloff et al. featured on the U.S. Department of Agriculture’s (USDA) Forest Service website, “The wildland-urban interface (WUI) is the area where houses and other human development meet or intermingle with undeveloped wildland vegetation” (https://research.fs.usda.gov/treesearch/14912). This zone is particularly vulnerable to wildfires, posing significant risks to lives and property.” See V.C. Radeloff et al., “The Wildland–Urban Interface in the United States,” Ecological Applications 15, no. 3 (2005): 799–805, https://doi.org/10.1890/04-1413.

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Radeloff et al., “Rising Wildfire Risk to Houses in the United States, Especially in Grasslands and Shrublands.” Science 382, no. 6671 (2023): 702–7, https://doi.org/10.1126/science.ade9223. 13 Miranda H. Mockrin et al., “Understanding the Wildland-Urban Interface (1990–2020),” Forest Service, USDA, last modified January 31, 2024, https://storymaps.arcgis.com/stories/6b2050a0ded0498c863ce30d73460c9e. 14 Mockrin et al. 15 CES. 16 Building Standards Commission, “History of the California Building Standards Code —Title 24 of the California Code of Regulations,” California Department of General Services, accessed July 29, 2025, https://www.dgs.ca.gov/BSC/About/History-of-the-California-Building-Standards-Code---Title-24. 17 International Code Council (ICC), “2024 International Wildland-Urban Interface Code (IWUIC),” accessed September 2025, https://codes.iccsafe.org/content/IWUIC2024V1.0. 18 John Brannen, “’Vulnerable People in Vulnerable Places’: How Costs and Climate Collide in Houston’s Housing System,” Kinder Institute for Urban Research, Rice University, June 19, 2025, https://kinder.rice.edu/urbanedge/vulnerable-people-vulnerable-places-how-costs-and-climate-collidehoustons-housing-system. 19 “Harris County Approves New Building Regulations Post-Harvey,” ABC13 Houston, December 5, 2017, https://abc13.com/post/harris-county-new-building-regulations-post-harvey-/2743685/; John R. Blount and Loyd Smith, “Regulations of Harris County, Texas for Floodplain Management,” Harris County and Federal Emergency Management Agency, last modified July 9, 2019, https://www.eng.hctx.net/portals/23/fpmregseffect190709.pdf. 20 Project Recovery, “Voluntary Residential Buyout Program,” accessed September 2025, https://www.harrisrecovery.org/Programs/Buyout/Voluntary-Buyout-Program; Project Recovery, “Post Disaster Relocation and Buyout Program,” accessed September 2025, https://www.harrisrecovery.org/Programs/Buyout/Post-Disaster-Relocation-and-Buyout. 21 “Industrialized Housing and Buildings – Adoption of New Code Editions,” Texas Department of Licensing and Regulation, June 17, 2024, https://www.tdlr.texas.gov/news/2024/06/17/industrialized-housing-andbuildings-adoption-of-new-code-editions/. 22 Federal Emergency Management Agency (FEMA), “Building Codes Save: A Nationwide Study of Loss Prevention,” last modified April 30, 2025, https://www.fema.gov/emergency-managers/riskmanagement/building-science/building-codes-save-study. 23 FEMA’s revised flood maps for Harris County are essential for accurate flood risk assessment, but they have been repeatedly delayed and are now projected to be released in early 2026. See Rebekah F. Ward, “Eight Years After Hurricane Harvey, FEMA Flood Map Updates for Harris County Delayed Again,” Houston Chronicle, May 2, 2025, https://www.houstonchronicle.com/news/houston-texas/environment/article/fema-flood-mapsharris-county-2026-20305161.php. 24 Vivek Denkanikotte, “The Evolution of Florida’s Building Codes & Their Impact on Multifamily Housing,” Trepp, January 21, 2025, https://www.trepp.com/trepptalk/evolution-of-florida-building-codes-and-impact-onmultifamily-housing. 25 Kevin M. Simmons et al., “Economic Effectiveness of Implementing a Statewide Building Code: The Case of Florida,” Land Economics 94, no. 2 (2018): 155–74, https://doi.org/10.3368/le.94.2.155 26 Simmons et al. 27 American Community Survey via Social Explorer, accessed September 2025, https://www.socialexplorer.com/tables/ACS2023. 28 Paul Hudson et al., “Moral Hazard in Natural Disaster Insurance Markets: Empirical Evidence from Germany and the United States,” Land Economics 93, no. 2 (2017): 179–208, https://doi.org/10.3368/le.93.2.179.

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Energy Insights 2026 Compiled by Kenneth B. Medlock III This publication was produced by Rice University’s Baker Institute for Public Policy and received limited editorial review prior to release. Wherever feasible, the material was reviewed by outside experts prior to release. Any errors or omissions are solely the responsibility of the author(s). This material may be quoted or reproduced without prior permission, provided appropriate credit is given to the author(s) and Rice University’s Baker Institute for Public Policy. The views expressed herein are those of the individual author(s) and do not necessarily represent the views of Rice University’s Baker Institute for Public Policy. Flipbook design and layout by James Deering.

Energy Insights 2025

Select Recent Publications and Resources The following is a curated library of recent publications and resources. More is available by visiting our website at http://www.bakerinstitute.org/center/center-energy-studies

Electricity Markets and Policy Resource: U.S. Data Centers and Infrastructure 1. The Defense Production Act’s Expanding Role in Energy 2. Energy Infrastructure and Politics in North America 3. Operational Constraints and the Merit Order Effect in ERCOT 4. How Investments Can Boost ERCOT Reliability and Cut Emissions 5. ‘Trainsmission’: An Old New Idea 6. The Energy Forum Podcast: Texas Grid Evolution and Its Intersection With Hurricanes, Demand Growth, and Resilience 7. Iraq’s Electricity Shortage and the Paradox of Gas Flaring 8. Technology Transition of the US Power Grid: Opportunities for Federal Engagement

Energy and Geopolitics - Eurasia Resource: Interactive Map of China Energy Infrastructure Data 1. China’s Electrostate Could Erode Deterrence in Asia 2. How Declining Oil Production Could Weaken Russia’s Geopolitical Power 3. China’s Strait of Hormuz Oil Security and Escalation Playbook 4. The Iran War’s Energy Aftershocks in the Philippines 5. Quantifying Ukraine’s Strikes on Russian Energy Infrastructure

Energy and Geopolitics - Middle East 1. Saudi Economic Policy as Vision 2030 Evolves 2. From Hormuz to the Red Sea — The Iran War’s Expansion 3. Electricity Subsidy Reform in Kuwait 4. Leveraging Oil, Gas, and Geography for Syria’s Postwar Recovery 5. How Institutional Barriers Shape Kuwait’s Energy Goals 6. Maritime Chokepoints and Risks to Global Shipping and Energy Security 7. Slow Depletion of Big Reserves Exposes Kuwait to Oil Demand Risks 8. Gulf Energy Transition Through Renewable Energy Development 9. The Energy Forum Podcast: Saudi Arabia Scales Back Vision 2030 Megaprojects, Shifts Focus to AI and Energy Energy Insights 2026

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Energy and Geopolitics - Latin America 1. Baker Briefing Podcast: Unpacking Venezuela’s Opaque Oil Deal 2. After Maduro’s Ouster, What Happens to Venezuela’s Oil? 3. Hydrocarbons and Mineral Resources in the Western Hemisphere 4. Building Barriers, Blocking Progress: Critical Minerals and Trade 5. Quantifying Investments in Mexico by China-Linked Entities 6. Indigenous Communities and Copper and Lithium Mining in Chile

Energy, Minerals, and Materials Resource: Global Minerals Production Dashboard Resource: Global Minerals Trade Dashboard 1. Bifurcated Reference Pricing As Market Architecture in Critical Minerals 2. Limiting Adversarial Capital in Critical Minerals Supply Chains 3. Byproduct Metals as a Constraint and Lever in Critical Minerals Finance 4. Technical Disclosure as a Gating Item in Critical Minerals Finance

Global Natural Gas 1. Rivalry, Conflict, and Opportunity in Eastern Mediterranean Natural Gas 2. Scenarios for Global Natural Gas Markets to 2050 3. US LNG Exports: Truth and Consequence Revisited

Global Oil 1. The Energy Forum Podcast: Hormuz Closures, Venezuela’s New Plan, and Oil’s Uncertain Path 2. The Energy Forum Podcast: Why Oil Markets Bounced Back 3. The Energy Forum Podcast: How the Strait of Hormuz’s Closure Could Reshape the Oil Market 4. Wars and Pipelines: How Armed Conflict Has Driven Oil Logistics Diversification 5. Losing Hormuz: The Costs of War for Gulf Oil Exporters 6. The Energy Forum Podcast: Live from CERAWeek: Latin America’s Growing Role in Global Oil Markets

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Select Recent Publications and Resources

Energy Technology and Innovation Policy 1. The Energy Forum Podcast: Can Batteries Help Power the AI Energy Demand? 2. The Energy Forum Podcast: Thinking Big With Small Reactors 3. The Defense Production Act’s Expanding Role in Energy 4. The Energy Forum Podcast: AI-Driven Energy Growth and Its Impact on Water Resources 5. AI Geoeconomics: Allied Electricity and Secure Data Centers

Sustainability and Resilience Resource: Natural Disaster Resilience dashboard 1. Public Perceptions of Advanced Recycling: Sustainability Summit 2026 2. Optimizing the Circular Economy Through Better Accounting 3. The Energy Forum Podcast: From Mechanical to Molecular: What ‘Advanced Recycling’ Actually Means 4. The Energy Forum Podcast: Beyond Recycling: The Global Systems Behind E-Waste 5. Sustainability in a Fragmented Global Economy: Managing Trade-Offs Across Interconnected Systems 6. The Lifecycle of Hydrocarbon Molecules: Limitations of the Plastic-Oil Debate 7. Geopolitical Conflict Highlights Circular Carbon Pathways in Plastics 8. Opening Schrödinger’s Box: Rethinking Carbon Beyond the Binary in Plastic Recycling 9. Microplastics, Fertility, and the Science Behind Headlines 10. From Controversy to Context: Evidence-Based Insights on Chemical Recycling

Transportation 1. The Energy Forum Podcast: What Is the Future of Hydrogen as a Fuel? 2. What to Know About Renewable Diesel and Biodiesel 3. A Strong Supply Chain Is the Circulatory System of a Healthy Economy 4. The Energy Forum Podcast: The Role of Ammonia in the Future of Fuels 5. The Energy Forum Podcast: The Future of Fuels 6. Houston’s Freeways: Who Was Displaced and Why?

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