NERC: The grid is even less prepared than we thought

But it doesn't have to be this way.

Happy Monday, and sorry to land in your inbox with some bad news. You may have heard that the North American Electric Reliability Corporation (NERC) recently released its 2025 Long-Term Reliability Assessment, and it isn’t pretty. Isaac Orr and I coauthored an op-ed in Townhall discussing NERC’s findings in the wake of Winter Storm Fern, which I’ll draw from in this piece.

Here’s the news, straight from NERC’s mouth.

The outlook has gotten worse

NERC finds that “13 of 23 assessment areas face resource adequacy challenges over the next 10 years.” Aggregated summer peak demand is forecast “to rise by over 224 GW,” which is 69% higher than last year’s 10-year growth projection, with data centers accounting for “most of the projected increase.”

Large swathes of the Northwest (NERC region WECC-Northwest), Midwest (MRO-MISO), Texas (RE-ERCOT), and the Northeast (RF-PJM) are at a “high risk” of shortfalls under normal peak conditions within the next five years.

NERC’s 2025 Long-Term Reliability Assessment

The prior year’s forecast, after a correction, didn’t find any areas of the U.S. at a high risk, but large portions of the country were at an “elevated” risk of shortfall under extreme conditions. Elevating five regions to a high risk — with three of them (PJM, MISO, and ERCOT) being three of the four largest RTOs in the U.S. by customers served — over the prior year is a big deal!

NERC’s 2024 Long-Term Reliability Assessment

NERC describes the reasons for its rapidly-declining outlook without mincing words (emphasis mine):

Projections for resource and transmission growth lag what is needed to support new data centers and other large loads that drive escalating demand forecasts. Most new resources in development to come on-line in the next five years consist of battery storage and solar photovoltaic (PV), which are inverter-based and weather-dependent resources that increase the complexity of planning and operating a reliable grid. Meanwhile, more fossil-fired generator retirements loom in the next five years, reducing the amount of generation that has fuel on site and impacting the system’s ability to respond to spikes in demand.

It’s a pretty simple equation at the end of the day: more demand + less dispatchable generation + more intermittent, weather-dependent resources = higher blackout risk.

Let’s look at the biggest RTOs.

Midcontinent Independent Systems Operator (MISO)

MISO, which serves all or parts of 15 states in the Midwest and South, is in for a tough couple of years. The area is expected to be at an elevated risk of shortfalls under extreme conditions by 2027 and to reach “high” risk by 2028, with a 7 GW shortfall.

Peak demand in MISO will reach 127 GW in the summer of 2026, growing to 143.7 GW by 2035. MISO has 54 GW of “predominantly solar and battery” nameplate capacity projected to come online in the next several years.

NERC isn’t accounting for resources MISO intends to bring online through the Expedited Resource Addition Study (ERAS) process, which NERC says would eliminate “the projected reserve margin shortfall” if the “projects come in as currently planned.” That’s a big if, given the uncertainty that permitting creates, but it could be a good sign that most of the ERAS projects seem to be natural gas.

PJM Interconnection

PJM, which serves all or part of 13 states and 67 million people, is expected to face “an extreme and rapid tightening of supply and demand for capacity resources,” facing potential shortfalls in 2029. PJM is experiencing some of the most vigorous data center development in the country, which is driving much of this escalating demand. PJM added 560 MW of new on-peak generation capacity since the prior year’s LTRA, but wind and solar contributed 96% of that capacity.

More startling is that NERC recognizes that, “Accelerated retirements, driven by unit age and environmental public policy, of generators” are driving supply below its installed reserve requirement by 2029. PJM “will be heavily reliant on good generation performance from both fossil and inverter-based generation” to avoid emergency procedures during peak operating periods.

As in MISO, there are new projects for expedited interconnection that were not considered in the LTRA, so things might get better — assuming these projects come online at all, in time, and are providing mostly reliable capacity rather than intermittent wind and solar. That’s a lot of ifs.

ERCOT

ERCOT is expecting an average annual increase of 5.6% to its summer peak internal demand. By 2029, the Texas grid will be facing a high risk of shortfall under normal peak conditions. In the non-winter months, ERCOT experiences the highest risks of shortfalls during “the early evening hours,” due to “the drop-off in solar generation and continued higher loads during those hours.” NERC notes that ERCOT, “has observed increasing errors in its load forecasts, which is problematic during extreme or unusual operating days,” like that in Winter Storm Fern.

The good news

Utilities and grid planners have responded to growing demand projections by pulling back 10 GW of confirmed and announced retirements over the next 10 years. While these “remain high and total over 105 GW in peak seasonal capacity, this is roughly 10 GW lower than the 10-year retirement projections last year.”

What if it could be more?

As Isaac Orr and I note in Townhall:

The good news is that it doesn’t have to happen this way. Reliable, dispatchable coal-fired generation can stay on the grid longer and run more frequently than the NERC report expects, thanks to Trump administration policies. Utilities must take Winter Storm Fern as a warning and stop shutting down reliable generation if they want to avert blackouts and protect families from rising costs.

In addition to several supportive executive orders, the Trump administration is
”repealing 2024 Biden rules regulating carbon dioxide emissions on power plants that would have forced coal plants to shut down in the next five years and hampered the economics of new natural gas plants.” When these rules are finalized, utilities will have the chance to reevaluate keeping their coal plants running longer. That could become even more important to do as building new gas turbines becomes more expensive.

That’s not what is happening right now, however. Existing capacity from “fossil-fueled generators fell by 21 GW,” over the prior year. And replacements won’t have the same reliability value to the grid, as over the next ten years, “solar and battery capacity additions represent two-thirds” of expected resource additions. Natural gas-fired generator additions represent 15%, with wind and hybrid at 8% each. Growing proportions of solar and battery sources means “the resource mix is becoming increasingly variable and weather-dependent,” which poses problems for grid operators.

Conclusion

NERC recommends that regulators and operators “carefully manage generator deactivations.” I’d go a step farther: stop prematurely retiring perfectly functional coal-fired generation. And if you must retire a resource, make sure it’s replaced with a reliable, affordable alternative like natural gas or nuclear — not wind and solar that complicate grid management, raise costs, and don’t show up to work when it matters most.

If this piece piqued your interest, you’ll like this post from the Energy Bad Boys:

NERC: Half of America At A High Risk of Blackouts