Where generation growth is no longer the binding constraint
EIA projects total U.S. electricity generation will rise 4.6% from early 2026 through end-2027, an incremental 198.8 million MWh. Wind and solar deliver 186.4 million MWh of that increase, or 93.7%. Layer in hydropower and the renewable share hits 98.5%. Coal and gas combined add just 1.3 million MWh. In nine of eleven major U.S. power markets, wind and solar output is projected to grow by 161 million MWh while coal and gas declines by 63 million MWh.
The capex bottleneck has shifted. Interconnection queues, transformer lead times, and storage siting now set the deployment pace more than module costs.
Two stress events, divergent answers
ERCOT hit a record 91,089 MW at 6 p.m. on July 22, 2026 — 5,508 MW above its August 2023 peak. During the comparable 2023 hour, real-time prices reached $4,477.12/MWh and stayed above $1,000/MWh through much of the afternoon. This July's peak hour cleared at $29.11/MWh. Solar output at the peak hour covered 31.5% of demand, up from roughly 12% in 2023. As solar faded after sunset, batteries supplied more than 10,000 MW for over an hour starting at 7:45 p.m., absorbing 10–14% of demand.
PJM tells the opposite story. Demand set a new record of 168,158 MW on July 2, 2026, above the 2006 high of 165,563 MW. Real-time prices neared $2,000/MWh in the peak hour and remained above $200/MWh from 11:10 a.m. to 9:30 p.m. Nearly three-quarters of PJM's projected generation growth through 2027 still comes from gas and coal, with aging coal responsible for roughly 44% of the increase, per IEEFA's analysis. The capacity-market bill is steep: IEEFA estimates PJM customers will pay nearly $50 billion in additional capacity costs over three years.
What to track through 2027
Storage depth is the next binding variable. ERCOT holds 21,864 MW of installed battery capacity today, with approximately another 16,000 MW expected by end-2027. CAISO carried 17,125 MW as of August 1, 2026. Watch four-hour-plus duration additions, interconnection queue clearance rates by ISO, and the frequency of real-time price tails above $500/MWh per RTO. Those metrics will show whether balance costs are being absorbed in capex — or deferred into utility bills.