Published February 16, 2026
By NZero
U.S. renewable energy deployment is accelerating at a historic pace. The February 2026 edition of the U.S. Energy Information Administration Short Term Energy Outlook projects continued expansion in solar and wind generation alongside rising electricity demand. National data points to a grid that is adding record clean capacity while supporting growth from data centers, advanced manufacturing, and electrification. Yet corporate energy risk is not defined by national averages. Companies operate within specific regional power markets, each with distinct transmission constraints, market structures, fuel mixes, and interconnection timelines. As renewable capacity scales and demand intensifies, regional grid realities are becoming central to cost management, reliability planning, and decarbonization strategy.
The February 2026 STEO forecasts strong growth in renewable generation over the next two years. Solar generation is expected to increase by 17 percent in 2026 and by a further 23 percent in 2027. Wind generation is projected to rise by 6 percent in 2026 and 7 percent in 2027. In absolute terms, EIA anticipates total U.S. solar generation will reach approximately 341 billion kilowatt hours in 2026 and 418 billion kilowatt hours in 2027, up from 291 billion kilowatt hours in 2025.
Capacity additions support this outlook. Nearly 70 gigawatts of new solar generating capacity are scheduled to come online across 2026 and 2027, representing about a 49 percent increase in solar operating capacity compared with the end of 2025. Recent federal infrastructure updates show that from January through November of the prior year, new solar additions totaled 25.4 gigawatts, compared with approximately 5.5 gigawatts of new wind and about 4 gigawatts of new natural gas capacity.
Renewables now account for roughly one quarter to one third of total U.S. electricity generation depending on season and demand conditions. Natural gas remains the largest single source of generation at around 40 percent of annual supply, while coal continues to decline relative to historical levels. The national emissions profile reflects these structural shifts, with power sector carbon dioxide emissions lower than a decade ago, though year over year reductions have moderated.
Electricity demand is also rising. Total U.S. consumption exceeds 4,000 billion kilowatt hours annually and is projected to reach new highs as commercial and industrial loads expand. Data center development, semiconductor manufacturing, and broader electrification trends are increasing electricity intensity in several regions. At a national scale, the system appears to be balancing growth in both supply and demand. However, national growth rates do not capture how unevenly these changes unfold across regions.
Regional grid structure plays a decisive role in shaping corporate energy exposure. ERCOT in Texas and PJM in the Mid Atlantic and Midwest illustrate how two large markets can present materially different risk environments.
ERCOT operates an energy only market without a centralized capacity market. Texas has become a leader in solar and wind deployment, particularly in West and South Texas. Rapid renewable buildout has increased supply during high resource periods, contributing to episodes of low or negative wholesale pricing in certain zones. These price dynamics reflect both abundant renewable output and transmission congestion between generation rich regions and urban load centers such as Dallas and Houston.
Transmission constraints can limit the deliverability of renewable power, increasing curtailment risk and creating nodal price volatility. For corporate buyers entering long term power purchase agreements in ERCOT, location within a specific pricing node can materially affect realized economics. Renewable capacity growth in Texas is substantial, yet grid congestion and infrastructure timing influence how that capacity translates into usable energy.
PJM operates both an energy market and a capacity market. In recent years, PJM has faced significant interconnection queue backlogs, with large volumes of proposed generation awaiting study and approval. Process reforms are underway, but development timelines remain extended. As a result, the pace at which new renewable capacity becomes operational can differ from the pace at which projects are proposed.
Natural gas continues to supply a large share of PJM generation, and capacity market outcomes influence investment signals across resource types. For companies operating in PJM, assumptions about rapid decarbonization based on national renewable statistics may not fully reflect regional integration timelines. Capacity prices, interconnection delays, and transmission planning all affect long term cost and emissions trajectories.
These differences highlight how market design and infrastructure constraints define regional exposure. In ERCOT, risk may center on congestion and price volatility. In PJM, it may relate more to interconnection timing and capacity market dynamics. National renewable growth does not eliminate these structural distinctions.
As renewable penetration increases, hourly system dynamics become more pronounced. In solar intensive regions, midday generation can exceed local demand during certain seasons, lowering marginal emissions intensity in those hours. Evening demand peaks may then rely more heavily on natural gas, raising carbon intensity. Wind dominant regions exhibit different seasonal and diurnal patterns. Regions with limited renewable penetration may maintain relatively stable but higher average emissions intensity across most hours.
Curtailment is one indicator of these dynamics. In parts of Texas and California, higher renewable output has coincided with increased curtailment during specific hours. Battery storage deployment is expanding and helps absorb excess generation, yet it does not fully eliminate imbalances. Curtailment affects both financial returns for generators and the realized carbon impact of renewable resources.
For companies with continuous operations, such as data centers and large manufacturing facilities, hourly carbon intensity is increasingly relevant. Annual renewable energy certificate accounting captures total contracted volumes but does not reflect temporal alignment between consumption and clean generation. Two facilities with identical annual electricity use may experience different real time emissions profiles depending on regional fuel mix and operating schedule.
Location decisions are therefore becoming integrated with energy strategy. When evaluating new sites, companies assess wholesale price trends, projected renewable additions, transmission capacity outlook, and interconnection timelines alongside traditional factors such as labor and logistics. Regions with strong renewable growth may offer long term decarbonization potential but also short term congestion risk. Other regions may provide stable infrastructure yet exhibit slower emissions reductions.
Combining national forecasts such as the STEO with regional ISO data enables more rigorous scenario analysis. Forward projections for fuel mix and demand growth can be paired with facility level load modeling to evaluate exposure to price volatility and carbon intensity shifts. This integrated approach supports capital allocation decisions that align financial resilience with emissions targets.
The U.S. power sector is adding renewable capacity at record levels, with solar generation expected to grow sharply through 2027 and tens of gigawatts of new capacity scheduled to come online. National electricity demand is also rising, driven by digital infrastructure and industrial expansion. The February 2026 STEO underscores these macro trends and projects continued evolution in fuel mix and generation volumes.
Yet corporate energy risk is defined by regional grid realities rather than national averages. ERCOT and PJM demonstrate how differences in market design, transmission infrastructure, and interconnection processes shape cost structures and decarbonization timelines. Curtailment patterns and hourly carbon intensity vary by geography, influencing the real world emissions impact of corporate electricity consumption.
For data centers and manufacturers expanding operations, understanding these regional dynamics is essential. Energy procurement, site selection, and long term capital planning increasingly depend on localized grid intelligence. Organizations that integrate national forecasts with granular regional analytics will be better positioned to manage volatility, align operations with lower carbon periods, and navigate an evolving power landscape.
