Can We Learn From the Texas Blackout in 2021 to Avoid What’s Coming?

Energy News Beat — The question is no longer whether Winter Storm Uri was a one-off. The question is whether the United States is still pricing electricity as if kilowatt-hours were interchangeable, when what grids actually sell is energy that shows up when people need it.

A widely circulated Electroverse post this weekend put the Texas story back in front of millions of viewers: the largest wind fleet in America, billions in subsidies, then a historic cold snap, collapsing output, a buckling grid, and a human cost measured in the hundreds of lives.

The video is blunt. The data underneath it is more complicated — and more useful.

Uri was not a morality play about one fuel. It was a systems failure. Natural gas plants accounted for the largest share of megawatts forced offline. Wind lost a huge number of units to icing and low output. Coal and even nuclear took hits. Frozen wellheads and processing plants cut gas supply. Load-shed then cut power to parts of the gas system itself. ERCOT had to dump roughly 20,000 MW of firm load — the largest controlled load-shed event in U.S. history — to keep the whole interconnection from going dark. More than 4.5 million Texans lost power. Official reviews attributed at least 210 deaths; later tallies and analyses put the number higher. Economic losses ran into the tens of billions.

Texas had nameplate capacity. It did not have winterized, fuel-secure, dispatchable capability at the scale the weather demanded. That distinction — capacity versus reliability — is the lesson the rest of the country still refuses to price.baigroupllc.com

What ERCOT Actually Fixed — and What It Still Has to Fix

Give Texas credit. After Uri, the Legislature, the Public Utility Commission, and ERCOT did more operational work than most grids have done after a near-collapse.

The first wave was physical and operational:

• Mandatory weatherization and inspections. ERCOT has completed thousands of generation and transmission inspections since December 2021 — well above PUC minimums — and tightened requirements by region and by past performance. Subsequent winter storms showed far fewer weather-related forced outages.
• Firm Fuel Supply Service, so participating generators hold on-site fuel for multi-day events.
  New ancillary products, including ERCOT Contingency Reserve Service (ECRS), to buy faster reserves.
• Market design changes aimed at price signals, reserve posture, and keeping thermal units available instead of chasing only the cheapest energy in ordinary hours.
• Batteries. Storage in ERCOT jumped by multiple gigawatts after 2021. Short-duration batteries do not replace a week of ice, but they have flattened the “peakiest peaks,” cut some emergency appeals, and given operators a tool they did not have in 2021.

Transmission. Hundreds of miles added or upgraded, with a Strategic Transmission Expansion Plan pointing toward thousands of miles of 765-kV extra-high-voltage lines.

Real-Time Co-optimization Plus Batteries (RTC+B), implemented in December 2025 — the biggest nodal-market upgrade since 2010 — to co-optimize energy, reserves, and battery dispatch in real time.

The results are not theoretical. Winter Storm Elliott in 2022 and Winter Storm Fern in January 2026 did not produce Uri-scale, systemwide blackouts. Reserves stayed healthier. Prices stayed under the revised caps. ERCOT and the PUC now say the grid has broken demand records in heat and cold without a repeat of 2021.

That is real progress. It is not the end of the story.

Independent analysis still warns that a repeat of Uri-level cold, with today’s load, could force load shedding. Batteries measured in two-to-four-hour blocks cannot carry a multi-day freeze. Gas additions still do more work than storage in those scenarios. Demand is exploding — data centers, manufacturing, electrification — and ERCOT has been among the fastest-growing grids in the country. The Texas Energy Fund and interconnection process are supposed to bring more dispatchable megawatts; first units are only now arriving. Retirements of thermal plants remain a live reliability risk if they outrun firm replacements.

Uri taught Texas to winterize what it already had. The next crisis will test whether Texas — and every other grid — built enough firm energy for a system that is adding load faster than it is adding reliability.Stop Calling It Replacement. It Is Energy Addition.

On Energy News Beat, we have said this for years: the United States is not swapping fossil fuels for wind and solar the way a homeowner swaps a furnace. We are in an energy addition. Total demand is rising. Wind and solar are being stacked on top of the system. Gas, coal, and nuclear still carry the hours when the weather does not cooperate. The only energy source civilization has fully retired is whale oil. Everything else is still here.

That is why the standard Levelized Cost of Electricity — plant-level dollars per megawatt-hour at the fence line — has become a policy weapon instead of an engineering tool. Lazard, IRENA, and agency charts can show cheap unsubsidized wind and solar on paper. Those charts, by their own footnotes, leave out bulk transmission, local distribution, reliability and reserve-margin costs, ancillary services, balancing, congestion, interconnection upgrades, curtailment, and the backup fleet that has to sit ready when the resource is not there.

That is not a “cost of electricity.” It is a cost of electrons in favorable hours.

What households and factories buy is energy services: heat, cooling, computation, industrial heat, and lights through a polar vortex and a heat dome.

Energy News Beat has argued for a shift from LCOE to a Levelized Cost of Energy — more precisely a Levelized Full System Cost of Energy (LFSCOE) or resiliency-adjusted system cost — that prices: firming and backup generation storage duration that matches the actual drought (hours vs. days vs. weeks) transmission and congestion inertia, frequency response, and voltage support weatherization and fuel security the cost of lost load when the model is wrong

Until that number is the one legislatures, PUCs, and ISOs use, “cheap renewables” will keep winning press releases while ratepayers fund the hidden system around them. We have called the old metric what it behaves like in politics: a Liars Cost of Energy. The fix is not to ban wind and solar. The fix is to stop letting them externalize reliability onto gas plants, ratepayers, and, in the worst hours, people sitting in the dark.

A new pricing paradigm has to treat grid resiliency as a product, not a residual. Capacity that can run for 72 hours on stored or dual fuel is not the same product as a midday solar block. Markets that pay them as if they were the same will keep getting the Texas 2021 outcome: lots of nameplate, not enough winter.

The Price Map Does Not Lie: Compare Texas to the Most Expensive States

Look at residential rates in the latest EIA-based snapshots for 2026. The U.S. average sits near 18.4¢/kWh. Texas is typically around 16.4¢ — below the national average. The most expensive jurisdictions are not the ones with the most oil wells. They are Hawaii, California, and a belt of Northeastern states.