Solar holds midday down; the 8 PM-9 PM net-load ramp is the test
Monday, Aug 17, 2026 · ERCOT data as of 8:00 AM CDT
Issue of Aug 17 · generated 8:08 AM CT20 newer issues
Tonight's 8 PM to 11 PM CDT ramp, not the 5 PM gross-load peak, is the day's binding test.
- Forecast gross load peaks at 90,414 MW at 5 PM CDT, the 99th percentile of the trailing 90-day range, and pre-storage net load reaches 72,346 MW at 9 PM CDT after an 11,922 MW/h ramp at 8 PM CDT, both in the 98th percentile of recent history.
- Since the prior issue the forecast load peak rose 3,393 MW and the West and South Hub cleared day-ahead curves rose $34.1/MWh and $24.9/MWh respectively.
- The cleared day-ahead curve prices hub highs between $114.9/MWh and $126.8/MWh from 8 PM to 10 PM CDT, while MetisCast's P50 path runs $10.2/MWh below that curve on average and diverges by $77/MWh at 10 PM CDT.
- Watch whether the cross-location median RT-DA spread holds inside -$9.8/MWh to $8.4/MWh and whether realized load stays within 2,250 MW of this morning's forecast vintage.
What changed since the last issue
Compared with the prior issue, West Hub cleared day-ahead price rose $34.1/MWh; South Hub cleared day-ahead price rose $24.9/MWh.
Notable readings
- Forecast gross-load peak revisionNow 90,414 MW
- +3,393 MW
- Largest net-load rampAug 17, 8 PM CDT
- 11,922 MW/h
- MetisCast versus cleared day-aheadMean across 17 joined hours
- -$10.2/MWh
- Recent common RT-DAAcross Aug 16 to Aug 17, 2026
- -$0.7/MWh
Evening Ramp, Not 5 PM Peak, Frames Today's Decision Window#
The decision window runs Aug 17, 4 PM CDT to 11 PM CDT, framed by the forecast gross-load peak and the cleared day-ahead high.
Three developments matter since the prior issue. The forecast gross-load peak rose 3,393 MW to 90,414 MW at 5 PM CDT. The West Hub cleared day-ahead curve rose $34.1/MWh and the South Hub curve rose $24.9/MWh. MetisCast's P50 path runs $10.2/MWh below the cleared day-ahead curve on average, widening to a $77/MWh gap at 10 PM CDT.
Three items earn desk attention into the close. Watch the cross-location median RT-DA spread against its -$9.8/MWh to $8.4/MWh band. Watch realized load against this morning's forecast vintage of 90,414 MW at 5 PM CDT. South Hub's raw RT-DA spread of -$1.4/MWh splits into a -$0.7/MWh common system component and a -$0.7/MWh local residual, both inside South Hub's own historical band.
| Window | System transition | ERCOT Hub Average day-ahead | Market posture |
|---|---|---|---|
| 8 AM-5 PM | Solar holds near its 34,878 MW high at 2 PM while gross load rises toward the afternoon peak. | $20.5/MWh to $36.6/MWh | Lowest-priced remaining window. Preserve flexibility for the evening. |
| 5 PM-8 PM | Gross load tops out at 90,414 MW and solar begins to fall, so net load accelerates. | $36.6/MWh to $118.7/MWh | Ramp begins. Watch load and renewable output against the forecast. |
| 8 PM-11 PM | Net load climbs 11,922 MW in the hour to 8 PM, peaks at 72,346 MW at 9 PM, and the cleared curve reaches its high. | $78.1/MWh to $120.6/MWh | Primary decision window. The day's outcome is settled here. |
| 11 PM-12 AM | Net load and cleared prices begin normalizing off the peak. | $38.2/MWh to $78.1/MWh | Reset once real time confirms the rollover. |
| Tightening | Easing |
|---|---|
| Forecast gross-load peak: 90,414 MW | Resource outage capacity in effect: 8,642 MW |
| Peak-load forecast revision: +3,393 MW | MetisCast P50 versus cleared day-ahead: -$10.2/MWh |
| Forecast pre-storage net-load peak: 72,346 MW | Common RT-DA convergence spread: -$0.7/MWh |
| Capacity less load and AS: -3,746 MW |
MetisCast's evening P50 undercuts the cleared day-ahead award by $10/MWh#
The cleared day-ahead curve prices a sharp evening premium across every hub tonight. North Hub and West Hub both clear at a $126.8/MWh high at 8 PM CDT, South Hub tops out at $114.9/MWh and Houston Hub at $118.8/MWh, both at 10 PM CDT, and the ERCOT Hub Average curve peaks at $120.6/MWh at 10 PM CDT. Since the prior issue, West Hub's cleared curve rose $34.1/MWh and South Hub's rose $24.9/MWh, lifting the ERCOT Hub Average curve $25.7/MWh. The evening award now prices materially above what desks saw last issue.
MetisCast, Ask the Grid's probabilistic price model issued at 7:45 AM CDT, prices the same transition lower. Its P50 path averages $10.2/MWh below the cleared curve across 17 joined hours, with a mean absolute divergence of $15.1/MWh, widening to $77/MWh at the 10 PM CDT hour where the cleared curve peaks. MetisCast's own P50 tops out earlier and lower, at $102.3/MWh at 8 PM CDT, two hours before the cleared award's 10 PM CDT high. Its uncertainty band is widest at 8 PM CDT, spanning roughly $206/MWh between the 10th and 90th percentile, so the model treats that hour as its least certain of the day.
The common RT-DA convergence component that underlies all four hubs sits at $-0.7/MWh across 24 joined hours, down $3.6/MWh from the prior issue but still inside the central part of its recent range. Every hub's real-time result to date sits close to this shared level, so real time has not separated toward either the cleared award or MetisCast's discount. The 8 PM-10 PM window is where that gets settled.
| Signal | Reading | Change | Trailing range | Context |
|---|---|---|---|---|
| Forecast gross-load peak | 90,414 MW at Aug 17, 5 PM CDT | +3,393 MW | 69,539 MW to 87,828 MW | high versus recent history (99th percentile of 89; realized daily gross-load peak, trailing 90 days) |
| Forecast pre-storage net-load peak | 72,346 MW at Aug 17, 9 PM CDT | - | 49,047 MW to 66,340 MW | high versus recent history (98th percentile of 89; realized daily pre-storage net-load peak, trailing 90 days) |
| Largest one-hour net-load ramp | 11,922 MW/h at Aug 17, 8 PM CDT | - | 5,248 MW/h to 10,462 MW/h | high versus recent history (98th percentile of 89; largest realized one-hour pre-storage net-load ramp per day, trailing 90 days) |
| ERCOT Hub Average MetisCast versus cleared day-ahead | -$10.2/MWh | - | - | MetisCast P50 minus cleared day-ahead, averaged across 17 joined hours. Largest single-hour gap $77/MWh at Aug 17, 10 PM CDT. Mean P10-P90 width $39.8/MWh across the frozen horizon, widest $206/MWh at Aug 17, 8 PM CDT. |
| Common RT-DA convergence spread | -$0.7/MWh | -$3.6/MWh | -$6.3/MWh to $4.7/MWh | inside the central recent range (52nd percentile of 88; mean RT-DA spread over a rolling 1-day window, preceding 90 days). The common component explains 51% of South Hub's -$1.4/MWh raw spread, leaving a -$0.7/MWh local residual. 4 of 4 locations sit inside their own absolute local residual over a rolling 1-day window, preceding 90 days band. |
| Resource outage capacity in effect | 8,642 MW | - | 8,040 MW to 18,812 MW | soft but not outside the recent range (16th percentile of 64; outage capacity in effect, same local hour and weekday type, trailing 90 days) |
| Latest system demand | 59,358 MW | - | 49,936 MW to 60,774 MW | elevated but inside the recent range (75th percentile of 63; same local hour and weekday type, trailing 90 days) |
MetisCast ERCOT Hub Average probabilistic price forecast#
MetisCast prices ERCOT Hub Average -$10.2/MWh against the cleared day-ahead curve across 17 joined hours. Its P50 tops out at $102.3/MWh at Aug 17, 8 PM CDT while the market cleared $120.6/MWh at Aug 17, 10 PM CDT. The two agree on when the evening matters and disagree on what it pays.
South Hub's discount to day-ahead is systemwide, not local stress#
The real-time discount to day-ahead splits into a common system component of -$0.7/MWh plus a local residual per hub. South Hub's raw -$1.4/MWh discount is roughly half systemwide, half local, leaving a -$0.7/MWh residual inside South's own rolling one-day band. North's -$0.1/MWh, West's -$1.0/MWh, and Houston's -$0.4/MWh discounts carry residuals near $0.6/MWh, -$0.2/MWh, and $0.35/MWh, each also inside its own band. No hub is separating from the system.
The real spatial split is in the day-ahead award timing: North and West clear their $126.8/MWh evening high at Aug 17, 8 PM CDT, while South's $114.9/MWh and Houston's $118.8/MWh highs, and the ERCOT Hub Average's $120.6/MWh peak, land two hours later at Aug 17, 10 PM CDT. Watch whether that gap holds as real time confirms tonight.
| Hub | Avg RT | Avg DA | RT-DA | RT max | RT min | Vs prior issue |
|---|---|---|---|---|---|---|
| ERCOT Hub Average | $31.2/MWh | $31.9/MWh | -$0.7/MWh | $86.7/MWh | $16.2/MWh | No material prior-issue change |
| North Hub | $31.8/MWh | $31.9/MWh | -$0.1/MWh | $94.7/MWh | $16.2/MWh | No material prior-issue change |
| South Hub | $29/MWh | $30.4/MWh | -$1.4/MWh | $73.5/MWh | $16.3/MWh | No material prior-issue change |
| West Hub | $31.3/MWh | $32.3/MWh | -$1/MWh | $93.2/MWh | $16.2/MWh | No material prior-issue change |
| Houston Hub | $32.5/MWh | $32.9/MWh | -$0.4/MWh | $85.3/MWh | $16.3/MWh | No material prior-issue change |
Outages stay soft while capacity margin tightens into tonight's peak#
Outages are not the story going into tonight. Forecast generation outage capacity in effect is 8,642 MW, soft against its recent same-hour history at the 16th percentile of the trailing 90-day range for this hour and weekday type, well inside the observed band rather than an elevated outage day.
The margin that matters sits elsewhere. Forecast committed capacity peaks at 115,093 MW at Aug 17, 5 PM CDT, the same hour forecast gross load tops out at 90,414 MW. Once the ancillary-service requirement is held constant against that load path, the calculated capacity-less-load figure turns negative into the evening, reaching -3,746 MW, the 1st percentile of its trailing 90-day sample of daily minimums. That reading excludes imports and the largest single contingency, so it marks a compressed calculated margin, not a scarcity finding.
Heat adds to the load side of that math: the hottest ERCOT weather zone reaches 104F and five of eight zones clear 100F in the vintage available at issuance, operating context for the load forecast rather than an independent price driver. Separately, ERCOT's Aug 16 filing of good-cause exceptions with the PUC for data-center audits following the Abbott memo is a load-growth and interconnection-queue risk item for desks to track, distinct from today's operating window. ERCOT Asks for Exceptions to Batch Study Process
Weather and load context#
NOAA/NWS regional maximum-temperature map#
| Signal | Observed state | Evidence status | Source |
|---|---|---|---|
| generation | WAP_WAP_G5 Forced Extension · 664 MW reduction | Operator-reported | ERCOT |
| generation | WAP_WAP_G6 Forced Extension · 663 MW reduction | Operator-reported | ERCOT |
| generation | SCES_UNIT1 Forced Extension · 933 MW reduction | Operator-reported | ERCOT |
| generation | HAYSEN_HAYSENG4 Forced Extension · 213 MW reduction | Operator-reported | ERCOT |
| generation | GIDEON_GIDEONG3 Maintenance Level 1 · 336 MW reduction | Operator-reported | ERCOT |
| generation | CALAVERS_OWS1 Unavoidable Extension · 420 MW reduction | Operator-reported | ERCOT |
| Location | Raw spread | Common component | Local residual | Own threshold | Verdict |
|---|---|---|---|---|---|
| ERCOT Hub Average | -$0.7/MWh | -$0.7/MWh | Reference | N/A | Defines the common component |
| North Hub | -$0.1/MWh | -$0.7/MWh | $0.6/MWh | $3.1/MWh | Inside its own band |
| South Hub | -$1.4/MWh | -$0.7/MWh | -$0.7/MWh | $3.3/MWh | Inside its own band |
| West Hub | -$1/MWh | -$0.7/MWh | -$0.2/MWh | $3.1/MWh | Inside its own band |
| Houston Hub | -$0.4/MWh | -$0.7/MWh | $0.4/MWh | $3.4/MWh | Inside its own band |
West Hub's $126.8 day-ahead peak sets tonight's watch level#
The decision window runs Aug 17, 4 PM to 11 PM CDT. West Hub's and North Hub's cleared day-ahead curves both peak at $126.8/MWh at 8 PM CDT, while South Hub tops out lower at $114.9/MWh and Houston Hub at $118.8/MWh, both at 10 PM CDT, spanning an 8 PM-10 PM CDT award window across hubs. Desks with day-ahead exposure should watch the Hub detail: real-time versus day-ahead charts and the ERCOT hub real-time price comparison chart tonight.
Three triggers matter: the cross-location median RT-DA spread staying between -$9.8/MWh and $8.4/MWh, system load tracking within 2,250 MW of the cutoff forecast, and any hub's local residual breaking its own threshold (West $6.7/MWh, South $6/MWh, Houston $6/MWh, North $5.4/MWh) while the system spread holds in band, marking that hub as separating from the system.
| Window | Confirmation | Invalidation |
|---|---|---|
| Aug 17, 4 PM CDT to Aug 17, 11 PM CDT | The cross-location median RT-DA spread stays between -$9.8/MWh and $8.4/MWh, its calibrated market-error band. Individual locations do not each have to reach their own award. Realized system load stays within 2,250 MW of the cutoff forecast vintage, the 90th percentile of 2160 lead-time-matched errors. | The cross-location median RT-DA spread falls below -$9.8/MWh. Realized system load falls more than 2,250 MW below the cutoff forecast vintage before the expected peak. |
| Scenario | Quantitative trigger | Interpretation | Action |
|---|---|---|---|
| Price: tighter than priced | Cross-location median RT-DA spread above $8.4/MWh. | Real time settles above the cleared curve across locations. | Check reserves, renewable performance and constraints for the cause. |
| Price: inside the recent error band | Cross-location median RT-DA spread between -$9.8/MWh and $8.4/MWh. | The cleared curve is validated within its usual error. | Keep the existing operating plan. |
| Price: softer than priced | Cross-location median RT-DA spread below -$9.8/MWh. | The cleared curve overstates the evening across locations. | Reprice the expected evening premium. |
| Load: above forecast | Realized load more than 2,250 MW above the cutoff vintage. | Demand is contributing more pressure than the frozen forecast assumed. It is one input to price formation, alongside renewable error, availability, interchange, reserves and congestion. | Quantify the demand contribution, then inspect supply and constraint conditions before attributing the price outcome. |
| Load: tracking forecast | Realized load within 2,250 MW of the cutoff vintage. | Aggregate demand error does not explain a price surprise in this window. | Inspect renewable forecast error, unit availability, reserves, interchange and constraint activation. |
| Load: below forecast | Realized load more than 2,250 MW below the cutoff vintage. | Demand provides an easing contribution against the frozen forecast. | Determine whether supply-side conditions offset or amplify it before attributing the price outcome. |
| Regional overlay | The cross-location median stays inside its band while at least one location's absolute local residual exceeds its own threshold. | One location separates from the system rather than the system moving. | Open the exact-time map on that location's constraints and generation. |
Each link opens Ask the Grid with the asset selected so the standard map info box is available.
| Term | Definition |
|---|---|
| RT-DA convergence spread | Real-time minus day-ahead price at the same settlement point, averaged over joined hours. Temporal, not locational: it is not basis. |
| Common component | The RT-DA spread shared across all selected locations, taken from the hub-average location where one exists and otherwise the cross-location mean. |
| Local residual | A location's RT-DA spread minus the common component. This, not the raw spread, is what a regional claim has to clear. |
| Pre-storage net load | Gross load forecast minus wind and solar forecast, over the hours where both renewable forecasts are published. Storage charge/discharge and net interchange are not included, which is why the narrower name is used. |
| Resource outage capacity in effect | Capacity carried by the outage records in force at the issue cutoff, as published in the operator's hourly outage curve. This is not the market's full forced-plus-unplanned outage total, and the two should not be compared across issues. |
| MetisCast P50 versus cleared day-ahead | Model median minus the cleared day-ahead award for the same hour. The day-ahead leg is a market outcome, not an Ask the Grid forecast. The stated P10-P90 width is an arithmetic mean across the frozen horizon unless labeled otherwise. |
| Quantity | Population |
|---|---|
| Forecast gross-load peak | realized daily gross-load peak, trailing 90 days (89 observations) |
| Forecast pre-storage net-load peak | realized daily pre-storage net-load peak, trailing 90 days (89 observations) |
| Largest one-hour net-load ramp | largest realized one-hour pre-storage net-load ramp per day, trailing 90 days (89 observations) |
| Resource outage capacity in effect | outage capacity in effect, same local hour and weekday type, trailing 90 days (64 observations) |
| Capacity less load and AS requirement | realized daily minimum committed capacity less load, holding today's AS requirement constant, trailing 90 days (87 observations) |
| RT-DA spread context | mean RT-DA spread over a rolling 1-day window, preceding 90 days |
| Local residual thresholds | absolute local residual over a rolling 1-day window, preceding 90 days |
| Market-error band | signed cross-location median hourly RT-DA spread, preceding 90 days |
| Scenario threshold population | Price and load are independent axes read together: a case on one never excludes a case on the other. Load is an attribution input, not a price verdict. Location thresholds: North Hub $5.4/MWh; South Hub $6/MWh; West Hub $6.7/MWh; Houston Hub $6/MWh. The load band is the P90 absolute error of 2160 lead-time-matched system load forecasts. |
Forecast-vintage policy. Every input in this issue was published at or before the knowledge cutoff. Forecast series are the latest vintage available at that instant and are never revised after the fact; realized history used for percentiles is guarded by the same cutoff. The preceding issue's frozen vintage is stored with the issue, so a revision is measured against what was actually published, not against a later correction. This issue could not close 3 analytical gaps: residual dispatchable demand, reserve, prc and contingency coverage, weather-to-market translation. Each is stated in the analysis rather than filled in by inference.
Source and quality note. 29 of 29 requested issue series were available; 16 longer-lookback series supported deterministic context. 14 event records were known at cutoff and 2 unchanged records were suppressed. Knowledge cutoff: Aug 17, 8:00 AM CDT.
Ask the agent
The agent answers from this issue and checks the live data.
Sources and web research
Web research: 1 current source contributed additional context to this issue.
- National Digital Forecast Database maximum-temperature forecast · NOAA/NWS · Official historical WMS rendering valid 2026-08-18T00:00:00.000Z UTC. The exact PNG bytes and source request were archived with this issue.
- MetisCast ERCOT Hub Average probabilistic price forecast · Metis · Leakage-safe forecast vintage issued Aug 17, 7:45 AM CDT. P10, P50, and P90 were hourly-averaged for comparison with the day-ahead market.
- ERCOT Asks for Exceptions to Batch Study Process · rtoinsider.com · Web research · 2026-08-16T00:00:00.000Z
1 Ask the Grid dataset, frozen at the issue cutoff
- Ask the Grid market and fundamentals series · Ask the Grid · Hourly real-time and day-ahead prices, demand, load forecast, and selected-asset series used in this issue.
Written by the grid agent from 29 market series, and checked against them before it was sent. All requested series were fetched.
All issues
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|---|---|---|
| Oct 10 to Oct 11, 2026 | Oct 11, 2026 | |
| Oct 9 to Oct 10, 2026 | Oct 10, 2026 | |
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