Leonard Hyman

Water scarcity is emerging as a threat to energy security because drought reduces hydropower output, limits cooling water for thermal and nuclear plants, disrupts fuel transport, and constrains electricity transmission. Rapidly expanding AI data centers are adding to demand for both electricity and water. The authors argue that markets alone cannot efficiently allocate water, since supplies are physically constrained, water is essential to households, environmental costs are often unpriced, and fragmented jurisdictions protect entrenched rights. They criticize the Trump administration for favoring water-intensive nuclear and coal generation while weakening climate and water protections, and urge energy-sector users and producers to plan cautiously for worsening conditions. Water is framed as a potentially defining commodity of the 21st century, with significant political and social tensions likely as shortages intensify.

The effective closure of the Strait of Hormuz has redirected commercial shipping around Africa, creating new opportunities for Somali pirates. Three tankers were reportedly hijacked between April and July 2026, while naval resources were diverted toward the Persian Gulf and Red Sea. The article links the resurgence to alleged cooperation between Houthi militants and Somali pirate networks, with Al-Shabaab providing onshore support. It also describes increasingly sophisticated operations, rising ransom demands and sharply higher war-risk insurance premiums, arguing that rerouting ships around Africa does not eliminate maritime security risks.

Iran’s five-month war with the United States and Israel has intensified an economic crisis already driven by sanctions, mismanagement, currency depreciation, and inflation. Iranian households are cutting consumption to basic necessities as food, medicine, utilities, and fuel become increasingly unaffordable, while unemployment and infrastructure damage deepen the strain. The IMF projects 68.9 percent consumer-price inflation in 2026 and a severe contraction. Washington is using sanctions and a naval blockade to restrict Iran’s oil revenue and foreign-currency access, apparently hoping economic pressure will force Tehran into a U.S.-favored peace agreement. Iran has resisted concessions and used control over the Strait of Hormuz to disrupt global energy markets. Analysts warn that the country could approach economic collapse within a year, with ordinary Iranians bearing the cost through shortages, reduced subsidies, and declining living standards.

Oil traders rebuilt the premium on crude futures after anticipated U.S.-Iran talks failed to produce a reopening agreement for the Strait of Hormuz, where tanker traffic remains far below normal. WTI rose more than 5% for the week and Brent briefly exceeded $90, but a 17.4-million-barrel U.S. crude inventory build and weaker 2026 demand forecasts from OPEC and the IEA limited the rally. Continued restrictions and attacks near alternative shipping routes support prices, while high fuel costs are weakening consumption. The outlook remains highly headline-driven, with vessel traffic, diplomatic progress, and further disruptions likely to determine whether prices rally or retreat.

Qatar, the United States and Argentina are leading a new wave of LNG investment intended to meet rising demand and strengthen energy security. The article highlights five major projects: QatarEnergy's North Field West expansion, Alaska LNG, Argentina LNG, NextDecade's Rio Grande LNG and Sempra Infrastructure's Port Arthur LNG. The projects collectively target substantial new export capacity, with first output generally expected between 2027 and the early 2030s. The outlook is supported by Shell's projection that global LNG demand could approach 700 million tonnes annually by 2050, but geopolitical risks have become more prominent after Iranian attacks damaged Qatari LNG infrastructure and disrupted shipping through the Strait of Hormuz.

U.S. commercial crude oil inventories increased by 17.4 million barrels in the week ending August 7, reaching 424.4 million barrels, or 2% below the five-year seasonal average. The increase exceeded the American Petroleum Institute’s earlier estimate of 9.072 million barrels and pressured crude futures, although Brent and WTI remained substantially higher than a week earlier. Gasoline inventories fell by 1 million barrels, while middle-distillate stocks declined by 100,000 barrels and remained 12% below the five-year average. Average U.S. petroleum products supplied over the past four weeks was down 2.1% year over year, indicating softer overall demand despite a 1.9% increase in distillate demand.

The United States and Gulf states are exploring infrastructure designed to reduce Iran’s leverage over the Strait of Hormuz and the Iran-backed Houthis’ influence over Bab el-Mandeb. One proposal is a $5 billion, 200,000-barrel-per-day refinery and export hub outside Hormuz, potentially in Oman or the UAE, linked to expanded India–Middle East–Europe trade routes. A more ambitious and reportedly secretive plan would move Gulf oil by pipeline across Saudi Arabia and Israel to Mediterranean ports via the Trans-Israel Pipeline. Supporters, including Israeli leaders and figures in Donald Trump’s administration, say the route could improve energy security and reinforce the Abraham Accords, while critics warn that Iran could target the infrastructure and make the project highly vulnerable.

Disruption around the Strait of Hormuz has weakened the long-standing assumption that energy shipments through the corridor will remain reliably accessible. Although Gulf producers retain unmatched resource quality, low costs and strategic importance, higher insurance, freight, inventory and investment risks could cause resilience and geopolitical exposure to receive greater weight in production economics. Capital may gradually favor Atlantic Margin producers in Brazil, Guyana, Canada and the United States, while also supporting enhanced oil recovery, deepwater projects, diversified export routes and technological innovation. The shift is expected to be gradual rather than a wholesale abandonment of Gulf supply, with millions of investment decisions eventually establishing a new energy-market equilibrium.

Europe has reduced its dependence on Russian fossil fuels but remains heavily reliant on imported oil, bringing in 435 million tonnes of crude in 2025 at a cost exceeding €212 billion. Citing a National Interest report, the article argues that the next major energy crisis may result from the gradual terminal decline of oil production in exporting countries rather than from war or sanctions. As fewer producers retain the ability to raise output during disruptions, diversification may become increasingly ineffective. The article urges Europe to accelerate its transition to indigenous clean energy to reduce exposure to energy shocks and foreign coercion.

The U.S. power grid needs roughly 5,000 miles of new high-voltage transmission lines annually, but additions fell from nearly 4,000 miles in 2013 to about 402 miles in 2025, averaging only 392 miles from 2022 through 2025. The authors argue that siting, permitting, regulatory and market-design problems are preventing sufficient grid expansion. New data centers and proposed nuclear or other power plants cannot reliably serve demand simply by being built nearby, because electricity flows throughout the interconnected network rather than directly from generator to customer. Unless transmission construction accelerates, developers may need to build generation off-grid, while policymakers risk pursuing projects that cannot operate reliably on the existing system.

Exelon CEO Calvin Butler warns that the United States could experience widespread blackouts by 2027 unless utilities are allowed to build additional power plants. The authors argue that competitive electricity markets have discouraged investment because developers face elevated risks without guaranteed utility ratepayer backing, while inflation-adjusted utility rate-base growth has remained modest despite rising future demand. They contend that grid modernization, including infrastructure for AI-related electricity consumption, will increase costs and may require market reforms, stronger regulation, or a return to utility-owned generation. If institutional changes cannot be implemented quickly, batteries and on-site generators may provide more immediate reliability, although deteriorating grid conditions could still produce localized outages.

The end of the Iran war could create short-term opportunities for reconstruction firms, defense manufacturers, and LNG suppliers, but rising supply after the conflict may weaken oil prices and demand. Energy consumers are likely to diversify away from geopolitically exposed Gulf, Russian, and potentially U.S. LNG supplies, increasing competition from domestic energy, nuclear power, renewables, and storage. The authors argue that energy efficiency, renewables, and batteries offer increasingly competitive and less volatile alternatives to fossil fuels, although Chinese manufacturers’ dominance of clean-energy supply chains could create a new geopolitical challenge. Overall, the war is expected to accelerate the shift toward non-fossil energy rather than produce major investment opportunities for the oil and gas industry.

The surge in electricity demand from artificial intelligence data centers is reviving arguments for public ownership and stronger regulation of utilities. The authors contend that U.S. utilities rely on unnecessarily high levels of expensive shareholder equity for a low-risk monopoly business, increasing consumer electricity costs, and estimate that government-backed debt financing could reduce bills by 10–15%. They argue that regulatory capture has weakened consumer protections, while publicly owned models such as France’s utilities, historical Japanese utilities and the Tennessee Valley Authority demonstrate the advantages of low-cost financing and tax exemptions. The emerging power-build cycle could also accelerate renewable deployment and reshape the political debate over whether electricity should be treated as an essential right rather than an ordinary business.

Electricity deregulation and market restructuring have not produced clear long-term savings for consumers, despite earlier projections of substantial cost reductions. Real electricity prices fell during the 1990s but have since fluctuated largely with fuel costs, while any efficiency gains appear to have been absorbed by other expenses. Future prices are expected to face upward pressure from grid investment requirements, higher interest rates, rising demand from data centers, natural-gas costs, transmission congestion, and deferred environmental and infrastructure spending. The authors conclude that the central challenge is whether the electricity industry can reliably expand and deliver power as costs rise.

U.S. electricity-grid reliability has deteriorated over decades, with outage duration increasing substantially even as outage frequency remained relatively stable. The authors argue that SAIDI, SAIFI, and CAIDI data show a persistent decline that is obscured when major-event days are excluded. Growing electricity demand from AI data centers, transmission congestion, extreme weather, and slow infrastructure expansion could worsen the trend. They contend that utility restructuring and government policy have failed to provide sufficient incentives for investment, leaving customers needing high reliability to develop their own power solutions and raising concerns about grid abandonment and energy equity.

Electricity prices in deregulated U.S. states have risen faster than those in regulated states over nearly three decades, with the gap now at its widest. The article attributes this largely to wholesale market design, in which the most expensive generator—often a natural-gas plant—sets the price paid to all generators. Policies that expand gas exports and gas-fired generation could raise domestic prices and volatility, especially as AI data centers increase demand. The authors argue that states should encourage renewable generation and address structural market weaknesses rather than restrict green energy, while consumers may consider solar panels and battery storage as protection against higher bills.

The United States is building more than 100 gas-fired power plants just as rising LNG exports are likely to expose domestic natural-gas prices to greater global volatility. The authors argue that utilities have underestimated fuel-price risk, leaving new plants vulnerable to repeated cost shocks, reduced utilization, or early abandonment. They contend that regulators will largely pass higher fuel costs to consumers, while batteries and renewable energy will become more attractive as their costs decline. The resulting competitive pressure could cause financial distress for gas-plant owners and accelerate the shift toward renewables.

Electric, natural-gas, and water utilities face long-term stranded-asset risks despite their traditionally stable dividends and investment-grade debt. Rising capital spending, high leverage, aging infrastructure, cheaper renewable power and storage, customer self-generation, environmental policy, and climate-related disruptions could undermine utilities’ ability to recover costs through regulated rates. Electric and gas companies may be exposed to obsolete fossil-fuel infrastructure and declining demand, while water utilities face costly replacements, resource shortages, and shrinking customer bases in affected areas. The authors argue that regulators may struggle to authorize the double-digit rate increases needed to preserve utility earnings without accelerating customer defections, potentially damaging bond ratings and common-stock returns.

Utilities moved from coal to natural gas because gas plants are more efficient, cheaper to operate, easier to maintain, and less costly to supply and dispose of waste from. However, the authors argue that wind, solar, and battery storage are now gaining an economic advantage because they have no fuel costs and increasingly offer lower levelized electricity costs. With roughly 18,000 MW of gas capacity under construction and another 98,000 MW in planning, the buildout could create stranded assets if renewables continue to capture market share. Battery storage is already competing with gas peaker plants in places such as California, although the transition is expected to unfold gradually over decades.

Britain’s light-touch regulation allowed Thames Water’s successive owners to extract cash, increase debt and underperform on water and sanitation obligations, eventually leaving shareholders wiped out and creditors competing to provide high-interest rescue financing. The authors argue that customers should not bear the costs of a failure caused by investors and management, warning that government support would create moral hazard. They contrast the UK approach with the more closely supervised U.S. utility model, in which regulators monitor financing and can force shareholders to absorb imprudent costs. The piece concludes that utilities should either be allowed to fail under a genuine free-market model or be tightly regulated and supported only when they have operated prudently, while citing New York City’s municipal water system as an example of an appropriate public-service model.

Greg Abel’s first Berkshire Hathaway annual meeting underscored both the opportunity created by surging electricity demand from AI and data centers and the growing risks facing regulated utilities. Berkshire’s MidAmerican Energy, PacifiCorp and NV Energy own roughly $90 billion in utility assets, but aging coal plants, stricter clean-energy mandates, inflation, pollution-control costs and potentially tens of billions of dollars in wildfire liabilities have made the business materially riskier. PacifiCorp has already settled wildfire claims, sought liability protections and agreed to sell its Washington assets to Portland General Electric. The analysis argues that rural service territories are especially vulnerable as solar-plus-battery systems enable customers to reduce reliance on the grid, and concludes that Berkshire’s utilities no longer have the same risk profile they had under Warren Buffett.

Advanced batteries, perovskite solar cells and nuclear fusion could disrupt the centralized electricity industry within five to ten years, according to Leonard Hyman and William Tilles. Cheaper storage combined with flexible, efficient solar panels could allow households and businesses to generate and store their own power, shrinking utilities’ customer base and potentially triggering a utility “death spiral.” Fusion could provide low-carbon baseload power while competing with small modular reactors and eventually fossil-fueled generation. The authors argue that utilities’ limited research spending and short investment horizons leave them poorly prepared, warning that a 5% decline in residential and commercial electricity sales could reduce pretax net income by 15–20% and create losses on redundant infrastructure.

Fusion companies need hundreds of millions or billions of dollars to commercialize, and several are turning to SPAC mergers as a faster alternative to traditional IPOs. The authors argue that SPACs impose substantial dilution, provide weaker investor protections, and are especially risky for pre-revenue fusion firms whose technologies may not succeed. TAE Enterprises is pursuing hydrogen-boron fusion with its Copernicus reactor, General Fusion plans a roughly $1 billion transaction and NASDAQ listing, and Zap Energy is developing a compact Z-pinch approach. Because these companies remain research-and-development projects with uncertain technological outcomes and no near-term revenues, the article concludes that SPAC shares are unsuitable for typical retail investors.

Private fusion companies are targeting commercially relevant prototypes and grid-scale plants between 2028 and the early 2030s, potentially bringing them into direct competition with the first new small modular reactors. Major unresolved challenges include achieving net energy gain, maintaining stable plasma, developing radiation-resistant materials, securing scarce tritium supplies and reducing construction costs. Commonwealth Fusion Systems, Inertia Enterprises and Helion have made aggressive deployment and cost claims, while ITER’s longer timeline highlights the uncertainty. Commercial progress will depend on access to capital, government support, scalable supply chains, successful technology selection and the cost of later reactor units. If the claims prove accurate, fusion could become a disruptive, lower-emissions competitor to conventional nuclear power and SMRs, creating substantial demand for new investment.

India has brought a domestically designed 500 MW sodium-cooled reactor at Kalpakkam to criticality, advancing its long-term strategy to use abundant thorium resources for greater energy security and lower carbon emissions. The reactor was delayed substantially, but the authors argue that its value should be assessed as part of a planned fleet of 18 reactors, alongside eight already under construction. India is pursuing control of the full nuclear supply chain, including mining, fuel processing, reactor design, construction, operations and waste management, while the United States is portrayed as having taken a more fragmented and market-driven approach. Despite the program's scale and high capital costs, nuclear power is expected to remain below five percent of India's electricity mix.

The article examines three developments with potentially major energy implications. A planned 300 MW GE Hitachi small modular reactor backed by the Tennessee Valley Authority could cost $5.4 billion, leading the authors to question nuclear power’s competitiveness unless first-of-a-kind costs fall substantially. Chinese AI companies are reportedly selling output tokens far more cheaply than U.S. firms, creating pressure on American pricing, market share, profits, and future electricity demand. Perovskite solar cells have achieved much higher reported efficiencies than conventional silicon in some configurations and could transform electricity generation if researchers overcome durability, flexibility, and reliability challenges.

Electricity demand, especially from AI data centers, may grow faster than power generation and grid infrastructure, increasing the risk of shortages, congestion and outages. Possible short-term responses include delaying the retirement of aging plants, enabling large users to self-generate with storage, or accepting lower service quality, but these approaches do not resolve structural capacity and transmission constraints. The authors argue that geopolitical conflicts, postwar reconstruction, equipment and engineering shortages, shifting U.S. administrations, and uncertainty surrounding AI demand make just-in-time planning dangerous for an essential public utility.

AI data centers that build their own nearby power plants may still affect the wider electricity network because power flows across interconnected systems, requiring costly and time-consuming transmission upgrades. Avoiding grid connections could increase data-center costs, backup requirements and pollution, but may lower electricity bills for conventional consumers and prevent utilities from expanding their rate bases. The trend also challenges expectations that surging AI-driven electricity demand will automatically benefit traditional power companies.