The Federal Reserve held the policy rate at 3.50–3.75% through the quarter, but the 17 June Summary of Economic Projections delivered a hawkish surprise. The updated dot plot showed a 3.8% median policy-rate projection for 2026, with nine members supporting further increases. Officials also raised their 2026 headline PCE inflation forecast to 3.6% from 2.7% in March, while the core PCE forecast increased to 3.3%.
Market pricing shifted decisively from an expectation of forthcoming rate cuts toward a “higher for longer” regime. This was more than a routine policy hold: it represented a material change in the rates backdrop, with implications for duration-sensitive equities, infrastructure valuations and portfolio hedging.
Growth nevertheless remained resilient. Equity markets more than reversed their earlier-2026 declines as Middle East conflict risk de-escalated, with technology leading the rebound after underperforming earlier in the year. Credit conditions also showed tentative signs of stabilisation, including tighter private-credit spreads and firmer business-development-company equity prices.
The underlying economic picture remains bifurcated. Strong AI capital expenditure and productivity growth are offsetting a consumer sector that is becoming increasingly reliant on wealth effects rather than income growth as real wages compress. The quarter can therefore be characterised as “resilient at the headline level, but fragile underneath”—a constructive environment for structural AI and power-infrastructure investment, but one that still warrants disciplined position sizing and active downside-risk management.
North American Energy Transition — Q2 2026: The Interconnection Bottleneck Becomes a Policy Story
The defining shift this quarter was not demand growth—that has been the story since 2024—but the migration of the constraint from capital availability to physical delivery. Washington increasingly treated the interconnection bottleneck as a national policy priority rather than a market imbalance that would resolve on its own.
FERC’s 18 June intervention was the quarter’s most consequential policy event. Rather than pursuing a multi-year rulemaking, FERC used Section 206 show-cause authority to give all six RTOs and ISOs 60 days to justify or rewrite their large-load interconnection tariffs, alongside a 30-day resource-adequacy reporting requirement. Under the emerging framework, data centres would bear their own interconnection costs, helping to protect ratepayers while reducing the procedural delays that have made grid connection the longest lead-time item in data-centre development.
This represents a genuine regime change in how large loads—not only generation—are regulated at the federal level. Implementation will not be frictionless. State regulators, including NARUC, have argued that federal standardisation could limit states’ ability to respond to regional conditions and protect affordability. Litigation and jurisdictional risk are therefore likely to run alongside implementation through the third and fourth quarters.
Co-location is becoming the dominant workaround, and it is reshaping capital allocation. On-site and behind-the-meter generation is projected to account for approximately 30% of new data-centre capacity in 2026, up from near zero a year earlier, with some forecasts suggesting it could reach 50% as hyperscalers secure direct generation partnerships. This creates a structural tailwind for gas-turbine OEMs, SMR developers, storage providers and distributed-power platforms.
The same shift also introduces stranded-asset risk for utilities. Capacity planned to serve large-load customers may never be required on the public grid if hyperscalers increasingly bypass traditional interconnection pathways. The key investment distinction is therefore moving from simple exposure to power demand toward exposure to the assets and technologies that shorten time to energisation.
The gas-versus-renewables mix has moved more decisively toward gas than consensus expected six months ago. Natural gas’ share of planned data-centre capacity increased from 11.1% to 18.1% between 2024 and 2026. Non-renewable additions rose approximately 71% from 2025 to 2026, while renewable growth flattened to around 2%. One important driver is economics: natural-gas interconnection costs are estimated at roughly one-tenth those of solar and offshore wind.
For the portfolio thesis, this complicates the view that AI demand will pull clean-energy deployment forward in a straight line. In the near term, AI demand is accelerating gas deployment more rapidly, while decarbonisation appears as a second-order effect through storage, SMRs, efficiency and distributed generation rather than through bulk renewable-grid supply alone.
The issue has also become a rates and inflation story. Data-centre-driven electricity demand has been estimated to add approximately 0.1 percentage points to core inflation in both 2026 and 2027, concentrated in PJM states, alongside a 2.3% year-on-year rise in national retail electricity prices. This creates a new macro transmission channel linking AI infrastructure demand, regional power inflation and Federal Reserve policy.
Q3 watch list: RTO compliance filings due in mid-August; additional state-level pushback or litigation; and whether the PJM emergency-capacity-auction structure—under which technology companies fund new plants directly—is replicated elsewhere. These developments should provide the clearest read-through on which infrastructure companies capture the co-location capex cycle and which utilities face the greatest stranded-asset risk.
The VIX closed the quarter near 17.6, consolidating in a base-building range above the 17 support zone after a prolonged decline from the earlier-year stress peak. Realised volatility has compressed materially, but the index has not returned to the ultra-low-volatility regime that characterised the most complacent phases of the cycle.
The SKEW Index remained elevated within its 132–162 52-week range and finished the quarter around 144. This combination—subdued realised volatility alongside persistent demand for tail protection—is consistent with a “calm but hedged” market structure.
Term structure and price action point to an ongoing volatility-compression cycle. Premium-selling remains active and front-end implied volatility is relatively inexpensive, while downside skew has stayed sticky. The market has largely removed the Middle East geopolitical premium, but has not yet fully repriced the risk of a more hawkish Federal Reserve into the tails.
The net signal is cheap at-the-money volatility but expensive downside convexity. Heading into the third quarter, this favours structured overlays—including put spreads, collars and selectively financed downside protection—over outright long-volatility exposure.
