ERCOT's December 2026 MORA Moves Peak Grid Risk to the 7 to 8 a.m. Hour: How Texas Commercial Buyers Should Hedge the Winter Morning Ramp
ERCOT's December 2026 MORA puts the month's highest grid emergency risk in the 7 to 8 a.m. hour, at 2.95%, well under its 10% threshold. For commercial buyers the timing matters more than the level: index exposure sits on the winter morning ramp, and winter peaks do not touch 4CP transmission charges.
On October 2, 2026, ERCOT published its Monthly Outlook for Resource Adequacy (MORA) for December 2026, and it names Hour Ending 8:00 a.m. CST, the 7:00 to 8:00 a.m. hour, as the riskiest hour of the month, with a 2.95% probability that ERCOT would need to declare an Energy Emergency Alert (EEA). That is well under ERCOT's 10% elevated-risk threshold, so this is not a shortage warning. For Texas commercial electricity buyers, the useful signal is the timing: grid risk moves from November's evening peak to the winter morning ramp, the same hour many businesses switch on heat, lights and equipment.
What Happened
ERCOT's December 2026 MORA, posted October 2, 2026, puts the month's highest EEA risk at Hour Ending 8:00 a.m. Central Standard Time with a 2.95% probability, against a deterministic load forecast of 75,148 MW for that hour on a December peak-load day. The forecast assumes average weather and includes new large loads expected online by December. ERCOT says its EEA probabilities "remain well below" the 10% level it treats as elevated risk.
The MORA is ERCOT's monthly probabilistic check on whether available generation will cover demand in a month roughly two months ahead. The shift from the prior report is the story here:
| MORA report | Posted | Highest EEA risk hour (CST) | EEA probability | Load forecast for that hour |
|---|---|---|---|---|
| November 2026 | Sept 3, 2026 | Hour Ending 7:00 p.m. (6 to 7 p.m.) | 3.40% | 65,446 MW |
| December 2026 | Oct 2, 2026 | Hour Ending 8:00 a.m. (7 to 8 a.m.) | 2.95% | 75,148 MW |
| January 2026 (last winter) | Nov 7, 2025 | Hour Ending 8:00 a.m. (7 to 8 a.m.) | 1.4% | 77,387 MW |
Source: ERCOT MORA reports for November 2026, December 2026 and January 2026.
Two things stand out. First, the risk hour flips from evening to morning. ERCOT's November report ties morning risk to cold temperatures before and during sunrise, when solar generation is insignificant, and December is when that window carries the month's peak. Second, the December 2026 morning probability of 2.95% is about twice the 1.4% ERCOT modeled for the January 2026 morning peak, even though the December load forecast is 2,239 MW lower. Different months carry different load, outage and weather inputs, so we read that as a reason to watch winter mornings, not as a trend line.
ERCOT also ran a severe winter storm case for the 8:00 a.m. hour, simulating loads from 78,000 MW to 90,000 MW with weather-related thermal outages and wind turbine icing. It called a 90,000 MW load in that hour "remote." Both the base and storm runs account for the PUCT weatherization standard and ERCOT's Firm Fuel Supply Service (FFSS), which pays qualifying generators to keep firm fuel available for winter.
Last winter shows why a low modeled number is not a promise of a quiet month. During Winter Storm Fern, ERCOT applied to the U.S. Department of Energy on January 24, 2026, and DOE issued emergency order 202-26-01 the same day, authorizing ERCOT to direct backup generation at data centers and other large load customers as a last resort before or during an EEA3, through January 27. ERCOT's post-event report says it did not need to call for conservation and did not issue an EEA, and its January monthly report says it did not need to implement the backup generation order.
Read the primary sources: the December 2026 MORA, the November 2026 MORA, and ERCOT's Winter Storm Fern post-event report.
Impact on Commercial Electricity Buyers in Texas
A 2.95% modeled risk will not change your bill by itself, but where that risk sits in the day decides who carries it. We see three channels where the December report reaches a commercial account: index exposure in the morning hour, the winter shape priced into fixed offers, and a transmission assumption worth retiring.
Index and pass-through exposure. If your contract passes ERCOT real-time prices through, for all of your load or a share of it, the 7 to 8 a.m. hour on a cold December weekday is where tight reserves would reach you. Real-time prices can jump without a declared emergency, as the $781/MWh real-time print on August 26 showed while day-ahead prices stayed under $100/MWh. A fixed all-in price moves that hour's risk to your retail electric provider.
Winter shape inside fixed offers. Providers price fixed commercial offers off forward wholesale prices for every month of the term, and winter mornings are part of that cost. A 12, 24 or 36 month contract starting this fall covers one, two or three winters. In the plans we track across all five TDU territories (Oncor, CenterPoint, AEP Texas Central, AEP Texas North and TNMP), median plan rates by territory sat between 6.36 and 6.56 cents per kWh in early October 2026, and the TxCP Commercial Rate Index (TCRI) stood at 7.09 cents per kWh in our October 5 weekly report. The TCRI is an average across every plan we track, so short-term and premium-priced plans pull it above the territory medians. Those bands are the reference point for any renewal quote this month, and a 2.95% modeled risk is not, on its own, a reason to accept a large winter premium above them.
Transmission charges stay a summer issue. Winter peaks do not set 4CP charges. Under PUCT rule 16 TAC 25.192, larger commercial accounts billed on 4CP pay transmission charges based on their demand during ERCOT's 15-minute system peaks in June, July, August and September. Cutting load at 7 a.m. in December lowers energy exposure for index buyers, but it does nothing for next year's transmission charge, which was set by intervals like the July 22 all-time peak.
The TxCP Winter Ramp Check: Three Questions Before December
Before December starts, run your contract through the same three questions we use to read a MORA report, so a low headline probability neither lulls you into ignoring your exposure nor pushes you into an expensive lock you do not need.
1. Who carries the 7 to 8 a.m. hour on my contract?
If the energy price is fixed and all-in for the full term, your provider carries it. If any share of your load floats on an index, or the contract passes through ERCOT market charges, you carry part of it.
2. Does my business add load to the morning ramp?
Electric heating, cooking equipment and production lines that start between 6 and 8 a.m. stack onto the grid's riskiest hour. For an index buyer, that is the load to shift first.
3. What happens to my price in a grid emergency?
Look for clauses on ERCOT emergencies, curtailment, force majeure and changes in market rules. Winter Storm Fern ended without an EEA, but DOE's January 24 order arrived the same day ERCOT asked for it, which shows how quickly emergency terms can come into play.
What You Should Do
Most commercial accounts can work through these four steps in a week, well before the December peak-load window, and they apply whether you buy on a fixed rate or an index.
- Pull your contract and Electricity Facts Label, then confirm whether your energy price is fixed all-in, partly indexed, or passes through ERCOT charges.
- If any load floats on an index, check your interval data for heating or equipment start-ups landing between 7 and 8 a.m. on cold days, and move what you can outside that hour.
- If your term ends between now and February 2027, request renewal quotes this month so a cold snap in the headlines does not set your price.
- Save peak-shaving effort aimed at transmission charges for June through September, when the 4CP intervals are set, and treat winter morning load shifting as an energy-cost move only.
Questions to Ask Your REP or Broker
These questions pin down how a provider handles winter morning risk, which rarely shows up on a rate comparison but decides who pays if a cold December morning gets tight on the ERCOT grid.
- Is my energy price fixed and all-in for every hour, including winter mornings, for the full term?
- If part of my load is indexed, which ERCOT price does it settle on, and what did that price average from 7 to 8 a.m. last December and January?
- Does the contract allow a price adjustment or extra charges if ERCOT declares an Energy Emergency Alert or the Department of Energy issues an emergency order?
- Do you offer, or partner with, a demand response program such as ERCOT's Emergency Response Service, and how is winter curtailment paid?
We will track the January 2027 MORA when ERCOT posts it, typically in early November. Subscribe to Weekly Market Insights, free. We publish a data-driven rate report every Monday.
For how the summer risk hour compared, see our read on ERCOT's July 2026 MORA and its 9 p.m. risk hour. To compare offers for your meter, browse current commercial rates by TDU or see every commercial plan we track in our data download.
Frequently Asked Questions
What is the ERCOT MORA report?
The Monthly Outlook for Resource Adequacy (MORA) is ERCOT's monthly probabilistic forecast of whether available generation will cover demand in a month about two months out. It names the hour with the highest Energy Emergency Alert risk and its probability. The December 2026 MORA, posted October 2, 2026, put that risk at 2.95% for the 7 to 8 a.m. hour.
What is the riskiest ERCOT hour in December 2026?
Hour Ending 8:00 a.m. CST, meaning the 7:00 to 8:00 a.m. hour, according to ERCOT's December 2026 MORA. ERCOT put the EEA probability at 2.95% with a 75,148 MW load forecast, well below its 10% elevated-risk threshold. In the November 2026 MORA, the riskiest hour was 6 to 7 p.m. at 3.40%.
Do winter peaks affect 4CP transmission charges in Texas?
No. Under PUCT rule 16 TAC 25.192, 4CP transmission charges are set by ERCOT's 15-minute system peaks in June, July, August and September. A December morning peak can raise energy costs for index buyers, but it does not change a commercial account's 4CP transmission charge.
Should a Texas business lock a fixed rate before winter?
It depends on your contract structure and term end date. A fixed all-in rate moves winter morning price risk to your provider. If your term ends before February 2027, compare quotes now against current aggregate bands: median plan rates by TDU territory sat between 6.36 and 6.56 cents per kWh in early October 2026.