Energy Market Reality Check

Table of Contents:

• Uncertain Ground for Energy Policy
• Growing Demand-Supply Imbalance
• Key Energy Markets to Watch
• Navigating Energy Market Complexity

Volatility is returning to the U.S. energy landscape, shaped by a mix of familiar pressures and new challenges. Demand for electricity and natural gas is surging nationwide, driven by multiyear trends in electrification, industrial load growth, and rapid data center expansion. Yet, the infrastructure to support these needs is struggling to keep pace. Tighter supply and demand imbalances are fueling higher prices and more pronounced market swings, particularly during peak periods.

During winter, these dynamics can lead to pipeline constraints — especially in the Northeast — as heating demand competes with power sector needs. A notable example is Winter Storm Elliot in December 2022, which caused a sharp spike in energy pricing due to widespread electric and natural gas infrastructure failures — including nearly 90,500 MW of unplanned power plant outages, sharp gas production declines, emergency load shedding, and fuel supply disruption. Although volatility is nothing new, today’s trajectory suggests that conditions could worsen if infrastructure development continues to lag.

Some grids designed for a single seasonal peak now face dual peaks. Lessons from Winter Storm Uri in 2021 — when Texas experienced widespread generation and supply failures — underscore today’s risks and the need for greater grid resiliency during summer heatwaves and extreme freezes.

Uncertain Ground for Energy Policy

Passage of the One Big Beautiful Bill Act (OBBBA) redefines the policy environment for U.S. energy development while introducing new regulatory uncertainty into project planning. The legislation phases down incentives and tax credits for renewable energy, particularly wind and solar. To receive full benefits, construction on eligible projects must begin within 12 months of July 4. Projects starting in 2026 or 2027 face steep credit step-downs before incentives are largely phased out. Developers face pressure to accelerate projects to secure maximum support.

Potential tariff hikes on key materials and the OBBBA’s Foreign Entity of Concern provisions add to the challenge, heightening scrutiny over component origins and potentially causing more selective sourcing from developers. While supply constraints have eased since the 2020 pandemic, uncertainty from this new policy could reverse some of that progress. Compared to relatively stable state policies, federal uncertainty makes longer-term generation asset investments — with 20-year lifespans — riskier, given that the financial outlook can shift midstream.

Fossil fuel infrastructure expansion faces its own headwinds. Regulatory hurdles and legal challenges have delayed projects over the past decade, especially as policy focus has shifted toward renewables. While the OBBBA includes provisions to streamline permitting, litigation could still slow progress. Across the country, most new capacity in the pipeline is renewable-focused. But with waning policy support and tighter timelines, some projects could be delayed — or removed — from the interconnection queue.

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Growing Demand-Supply Imbalance

Energy demand is accelerating at an unprecedented rate, driven in large part by data center growth. According to the U.S. Department of Energy, data center load has tripled over the past decade and is projected to double or triple again by 2028, at which point these facilities are expected to consume 6.7% to 12% of total U.S. electricity. Running 24/7 with little downtime, they permanently increase baseload demand. In smaller markets, a single facility can consume a significant share of regional capacity.

This is compounded by broader electrification — from electric vehicle adoption to expanded air conditioning — which steadily increases loads on already aging grids that are inflexible and unable to keep pace. Combined with slower generation growth, these conditions increase the risk of volatility and rolling blackouts. Battery storage helps bridge peak load gaps, and new technologies could further reduce volatility, but deployment still trails demand growth.

At the same time, tariffs are raising costs for critical materials needed to expand and modernize the grid, including copper, steel, and aluminum. Higher costs could delay projects and slow construction timelines, increasing the risk of capacity constraints — and further tightening the supply-demand balance.

Key Energy Markets to Watch

• PJM (Mid-Atlantic and Midwest) is reforming its capacity market to counter years of artificially low prices from subsidized renewables. These pressures made it difficult for traditional generation to remain viable, leading to significant baseload retirements. The reforms aim to strengthen reliability and encourage new generation from all sources while clearing interconnection queue backlogs.

• ERCOT (Texas) is experiencing sustained load growth from economic expansion, industrial activity, and data center development. Without a capacity market, ERCOT relies on real-time price signals to incentivize generation. Transmission congestion from West Texas to eastern population centers remains a challenge, especially during extreme heat or cold. Battery storage has helped offset some of the risk.

• NYISO (New York) is seeing peaker and nuclear retirements converge with ambitious decarbonization goals and increased reliance on imported hydropower from Quebec. Energy market reform is a top priority. In Zone J (New York City), rates are expected to remain elevated through at least the winter 2025/26 capacity period. In Zones H, I, and Upstate, rates have steadied, but delays in generation or transmission projects could drive increases.

• ISO-NE (New England) faces severe pipeline constraints and increasing reliance on LNG imports and fuel oil during winter peaks, exposing prices to oil market volatility. Fuel security remains critical, with limited prospects for infrastructure expansion. The region must also navigate capacity market reform, gas supply challenges, and transmission constraints, making the balance of reliability, efficiency, and affordability essential.

• MISO (Midcontinent) is experiencing a persistent mismatch between northern demand and southern generation capacity. This issue raises concerns over transmission constraints and reliability, especially during heat events when transmission from south to north is limited. Rising renewable penetration adds complexity to grid stability, while new capacity isn’t sufficiently offsetting reduced imports and higher fossil fuel retirements.

• CAISO (California) continues to contend with wildfire risks. The rapid buildout of large-scale battery storage — particularly in the southern region of the state — has reduced historical volatility, a notable development. Resource adequacy supply (the ability of the grid to meet electrical demand at any time) will remain the key pricing driver and is expected to stay tight through 2030.

Navigating Energy Market Complexity

In today’s energy market, proactive communication, comprehensive procurement approaches, and agile execution are crucial. Detailed, real-time data is essential for shaping procurement and energy management strategies that address each company’s exposure to volatility. ENGIE Impact acts as an extension of each client’s team, applying market insights to develop strategic and adaptable plans. By integrating renewable, conventional, and rate-optimization solutions, ENGIE Impact helps organizations meet budgetary targets and strengthen operational resilience in an increasingly complex market.