Yesterday, West was cheap.
Today, the evening price outlook jumps.
A full-day November 2 5-minute hub LMP as reported by Ask the Grid. ERCOT's official 15-minute settlement-point file shows a West Hub mean of $12.74 and a West load-zone mean of $16.22 (our calculation). It is a historical wholesale benchmark, not the same as the 15-minute settlement series below.
A November 2 afternoon auction price for November 3 delivery, up $47.10/MWh from the previous delivery day. ERCOT's official Nov 3 file gives $65.01. This regional average is not a retail offer.
The most expensive cited West hourly day-ahead price, for 10–11 p.m. It shows what the market priced in advance—not what customers will necessarily pay.
A single official 15-minute real-time settlement at 7:15 a.m.; $41.79/MWh higher than North. One interval is not an all-day average.
Forecast systemwide daily peak, not actual demand at 8 a.m. This is 7.1 GW lower than Monday’s forecast peak.
A dated indicative December natural-gas futures price, up $0.032/MMBtu (1.12%) versus the displayed prior settlement—not a Texas gas cash price.
The data we verified show a location-and-hour price difference.
A $21.30/MWh day-over-day regional basis reversal in day-ahead pricing.
On the same 24-hour load-zone series, West-minus-North moved from −$8.30/MWh on November 2 to +$13.00/MWh for November 3. That is a $21.30/MWh shift in the relative daily DAM curve. These are auctions for different delivery days, not the day-ahead-versus-real-time spread. [26]
Within today's auction curve, West's 10–11 a.m. trough ($0.80) to 10–11 p.m. peak ($201.90) is a $201.10/MWh hourly spread. It is a large intraday spread in one zone’s day-ahead prices. [26]
Today's real-time West premium appeared, then largely dissipated in 45 minutes.
Official 15-minute West-minus-North load-zone basis was +$41.79 at 07:15, +$46.75 at 07:30, +$30.43 at 07:45, then +$4.28/MWh at 08:00. West hub behaved differently: +$19.09, +$19.00, +$10.95, then −$0.46/MWh. [9]
That zone-versus-hub divergence is actionable as a question about location and hedge settlement, but does not identify a specific binding constraint or a cause. [6] [15]
Two things can happen at once: Texas can have enough overall power to meet demand, and electricity can still become expensive at a particular location or hour. Today, the big difference is where and when power is needed. Reserve and outage totals were not verified.
A one-day wholesale price is not a retail rate. Fixed-rate retail contracts are generally priced against expected costs over many future months. This report did not measure any retail offer or Electricity Facts Label. [26] [25]
Prices are up for today’s delivery—but that is not the same as a new retail rate.
24-hour arithmetic average of published hourly load-zone DAM prices for each delivery day. Selectra's republication, checked against ERCOT's official DAM files (24-hour load-zone means: West $17.86 → $65.01, North $26.19 → $51.95, Houston $40.26 → $68.31, South $33.01 → $66.97). The November 3 delivery auction was published on November 2 afternoon (reported 13:02 CT). [29] [30] [26]
Electricity producers and buyers agree on prices for each hour one day before that power is delivered. That is why these November 3 prices came from Monday afternoon’s auction. They are useful for understanding short-term costs, but the number in a residential contract is calculated very differently.
The West average went from $17.90 to $65.00 per megawatt-hour across two delivery days—an increase of $47.10/MWh. These are West load-zone averages. ERCOT's West Hub day-ahead average for Nov 2 was $14.47 (shown in our Nov 2 report); for Nov 3 it is $57.41. North, Houston and South also rose in the same series. That makes the move broader than one West price point, although it does not prove that long-term supplier costs rose by the same amount. [26]
Comparable day-ahead averages · $/MWh
| Load zone | Mon 02 | Tue 03 | Change |
|---|---|---|---|
| West | $17.90 | $65.00 | +$47.10 (+263%) |
| North | $26.20 | $52.00 | +$25.80 (+98%) |
| Houston | $40.30 | $68.30 | +$28.00 (+69%) |
| South | $33.00 | $67.00 | +$34.00 (+103%) |
Today’s Nov 3 DAM LZ average by region
The annual futures strips below are dated supplier marks; do not treat them as the same product as these DAM hourly delivery results.
West hourly DAM shape: two verified display points
These are two hourly scheduled day-ahead prices, not a verified full 24-point hourly curve. West's late peak occurs after solar production hours; the timestamp does not prove solar decline was its cause. [26]
Other zones' published late-evening DAM peaks
The maximum hours differ; these peak figures are not synchronized regional spreads. For same-hour basis, retrieve official 24×load-zone DAM table. [26]
The reported West day-ahead price is almost zero for 10–11 a.m. ($0.80/MWh), then reaches $201.90/MWh from 10–11 p.m.. That is a $201.10/MWh spread between those two hours. It suggests buyers expect electricity to be harder or costlier to supply late in the day.
What we cannot conclude: this alone does not prove which generator, weather change or transmission line caused the high price. The evening hour had not happened at the 8 a.m. reporting cutoff, and the hourly figures were republished by Selectra and match ERCOT's official DAM file. [26]
The West premium flared at sunrise, then faded in less than an hour.
ERCOT PRIMARY · FULL OVERNIGHT SLICE Operating day Tuesday, November 3, 2026; all 32 reported 15-minute interval-ending values from 00:15–08:00 CST. They include real-time reliability deployment price adders. The chart is not a completed day's average. [9]
These are actual 15-minute wholesale settlement prices through 8:00 a.m., not guesses about tonight. The West load zone was $46.75/MWh higher than North at 7:30 a.m., but only $4.28/MWh higher by 8:00 a.m.. That rapid reversal shows how misleading it would be to project a single peak over a full bill or contract. [9]
A hub is a pricing reference based on several grid locations. A load zone reflects electricity delivered across customer-serving areas. At 7:30, West’s own load zone was $27.81/MWh above West Hub; a contract pegged to the hub might therefore track customer-area cost imperfectly. The price difference is real, but the physical equipment responsible has not been established. [9]
Morning hub-versus-load-zone basis · same 15-minute intervals
| Interval ending CST | West HB | North HB | West LZ | North LZ | HB West−North | LZ West−North | West LZ−HB |
|---|---|---|---|---|---|---|---|
| 07:00 | $40.63 | $31.08 | $46.66 | $31.12 | +9.55 | +15.54 | +6.03 |
| 07:15 | $50.90 | $31.81 | $73.62 | $31.83 | +19.09 | +41.79 | +22.72 |
| 07:30 | $44.94 | $25.94 | $72.75 | $26.00 | +19.00 | +46.75 | +27.81 |
| 07:45 | $28.98 | $18.03 | $48.34 | $17.91 | +10.95 | +30.43 | +19.36 |
| 08:00 | $11.93 | $12.39 | $15.28 | $11.00 | -0.46 | +4.28 | +3.35 |
At 07:30, West load-zone price exceeded its own hub by $27.81/MWh. A hub-indexed hedge can therefore fail to match a load-zone charge in stressed intervals. The named contingency, 5-minute shadow price, outage and constraint path were not established. Without those records, congestion is an interpretation of differential settlement points, not a proven physical event attribution. [9] [6]
Demand is forecast to ease. Local bottlenecks can still make prices jump.
The expected systemwide peak falls from 66.5 GW Monday to 59.4 GW Tuesday in the available forecast—a 7.1-GW, or roughly 11%, lower peak. All else equal, needing less electricity usually reduces the chance that the last, most expensive generating units must be called on.
That makes the high West evening price notable: the market can anticipate a costly hour even on a lower-demand day. Weather, grid limitations and the exact hours of renewable generation all matter, so demand alone cannot establish the cause. The forecast is a dated secondary summary, not a refreshed official seven-day series. Our Nov 2 report showed 66.43 GW for Monday and 59.07 GW for Tuesday (Ask the Grid, earlier vintage); the figures here are 66.5 and 59.4 GW (GridVigil). Neither is ERCOT's own file. [25]
Five available days of the seven-day load outlook
ERCOT-derived daily peak forecast via GridVigil, vintage as of November 2, 2026 (updated 20:47 UTC / 14:47 CST). Secondary-source, not independent ERCOT MTLF verification; Saturday and Sunday were not provided. [25]
Today versus Monday: 59.4 GW versus 66.5 GW forecasted peaks (−7.1 GW, −10.7%). This is a comparison of forecasted daily peak levels, not a change in revisions to the same day. The next two forecast days are not verified. A modeled 18.29% projected reserve margin on the secondary site is not the official real-time operating-reserve margin or spare capacity. [25]
Early-morning North Texas weather
DFW 08:00: approximately 65°F, sunny, west-northwest wind around 10 mph in the weather service's 00:26 CST forecast vintage; temperatures around 72°F by midday. A mild local profile offers less cooling-load pressure than a high-90s heat day, but it cannot be turned into a Texas-wide MW estimate without a validated weather/load sensitivity model. [28] [19]
Independent indicator, clearly dated
GridVigil's Nov 2 05:00 UTC fuel mix snapshot displayed wind 23,428 MW, gas 22,547 MW, coal 5,626 MW, nuclear 3,832 MW; that observation predates this morning and must not be used as a Nov 3 generation estimate. Its 450 GW large-load interconnection requests are pipeline requests, not committed or energized load. [25]
Gas inventories offer some relief; longer-dated power prices tell a different story from a one-day spike.
Gas is an important fuel for Texas power plants. When storage builds faster than expected, traders often see less near-term fuel scarcity. The latest weekly release showed a +80 billion cubic feet U.S. injection, against a cited +72 Bcf expectation. However, South Central storage—more relevant to Texas—was still 28 Bcf below its normal five-year level. These forces point in different directions, not to a certain electricity price cut. [23] [3]
December gas futures separately rose from $2.856 to $2.888/MMBtu on the ENGIE display, a roughly 1.12% increase. Gas traders were therefore not simply treating the storage build as a reason to mark every future price lower. One gas session does not set a new residential or commercial electricity contract by itself. [4]
EIA: storage divergence within the headline +80 Bcf
EIA PRIMARY · RELEASE 29 OCT Week ended October 23, 2026 (not 3 Nov): Lower-48 gas in storage 3,724 Bcf, up 80 Bcf, 38 Bcf (1.0%) above five-year average but 147 Bcf (3.8%) below year ago. South Central stocks 1,168 Bcf, up 43 Bcf, yet 28 Bcf (2.3%) below five-year average. Its 43 Bcf injection is 53.75% of the U.S. build, and the 23 Bcf salt-cavern build is ~53.5% of South Central's injection. [23]
NRG's October 30 commentary cited a 72 Bcf market expectation, so the +8 Bcf national surprise matters for prompt gas pricing. This is an analyst expectation comparison, not a statistically established analyst-consensus value. [3] [23]
Prompt Henry Hub vs dated Waha spot
The Dec-2026 futures increase from $2.856 to $2.888 equals $0.032/MMBtu or 1.12%; ENGIE's displayed 0.011% is inconsistent with its own absolute numbers, so this report computes the change. Do not subtract the October 30 Waha spot price from November 3 December futures and call it a basis. The independently dated Oct 27 matched spot basis was −$1.35/MMBtu. [4] [13]
In the Permian, discounted Waha gas may signal transportation/associated-gas economics, but it does not on its own reveal an available pipeline path or explain an electricity transmission constraint. [13]
Supplier forward comparison · 29 Oct marks
Vistra's weekly PDF (p.1, dated Oct 29 marks; week ended Oct 30), in 7×24 delivery strips, not today's hourly DAM auction: [1]
Houston–North dated basis: $1.81/MWh for both Cal27 and Cal29. Compared with October 28, Cal27 Houston fell $0.13 and North fell $0.24; Cal29 Houston rose $0.58 and North rose $0.40. Do not extrapolate November 3 settlement basis into 2027. [1]
A forward price represents the market’s price for power delivered in a future month or year. Suppliers often use these longer-term prices when deciding what fixed contracts to offer. In Vistra’s October 29 marks, calendar-2027 Houston fell $0.13/MWh and North fell $0.24/MWh from October 28, while NextEra’s older October 28 comparison had calendar-2026 ERCOT $2.43/MWh lower over two weeks. [1] [5]
Those dated declines are not live November 3 quotes. They are dated supplier marks, not retail offers.
NextEra + Constellation perspective
NextEra's October 28 Energy Pulse PDF p.1 reports ERCOT Cal26 $39.33/MWh (−$2.43 over two weeks) and Henry Hub Cal26 $2.99/MMBtu (−$0.26). They are different vintages and delivery strips from today's prompt DEC gas and Cal27 Vistra marks. [5]
Constellation's October 26 weekly note puts October month-to-date U.S. gas output around 110 Bcf/day and 2027–31 NYMEX strips at $3.00, $3.63, $3.66, $3.65, $3.61/MMBtu; these are stale week-of-October-26 marks. NRG's November 2 report describes December 2026 prompt having settled Friday at $2.898/MMBtu and Cal27/Cal28 weekly drops of $0.09/$0.06. [2] [3]
Traders are leaning bearish on one gas benchmark, but that is not a prediction of retail prices.
The October 27 CFTC report shows NYMEX natural-gas money managers holding 206,317 more short contracts than long contracts. In plain English, this group had more bets benefiting from falling futures prices than from rising ones. Its net position became 48,908 contracts more negative over the preceding week. [24]
That is useful background for how strongly traders are positioned. It does not prove that gas or power prices will fall: expectations can change, and traders can reverse crowded positions quickly. Also, the CFTC data are from the prior Tuesday, not this morning.
Managed-money futures positioning · CFTC
PRIMARY CFTC · OBSERVED TUE 27 OCT · RELEASE FRI 30 OCT CFTC's disaggregated report yields NYMEX natural gas (023651) net −206,317 contracts, with 198,900 long and 405,217 short, a −48,908-contract weekly change. [24]
A separate ICE NAT GAS LD1 contract (023391, 2,500-MMBtu size) shows 547,178 long, 498,033 short, net +49,145, down 81,943 week-over-week. Positions in these contracts cannot simply be added as if each had the same size, delivery, or risk exposure. [18] [24]
Power assets, policy and operational event checks
Generator calendar: RWE's first-nine-months results are scheduled for Nov 11; its 3 Nov German power-station announcement has no verified 8 a.m. Central publication time and is excluded from the cutoff headline. [11]
Nuclear: Current Comanche Peak and South Texas Project unit availability percentages were not verified as of the cutoff.
Policy: ERCOT operations messages, NPRR log and PUCT Interchange were checked; no specific approved rule or transmission switching event can be causally linked to today's West basis without a dated record. [15] [17]
Low-relevance instrumentation: NOAA Kp index was 1.67 at 09:00 UTC (03:00 CST) Nov 3; there is no supporting evidence it drove ERCOT prices. Nearby SPP interchange and USGS water conditions could not be tied quantitatively to ERCOT. [21] [22]
What this means for the people actually buying, selling and investing in electricity.
Will residential electricity offers go up? Not necessarily: one day of wholesale prices does not set a new offer.
The short answer: This report measured wholesale prices, not retail offers. West’s day-ahead average rose from $17.90/MWh for Monday to $65.00/MWh for Tuesday, but that is a one-day wholesale change, not a change to residential contracts. At the same time, the available system load forecast is 7.1 GW lower for Tuesday’s peak than Monday’s, and older supplier forward-price comparisons were declining, not surging. [26] [25] [5]
How wholesale prices reach households: A fixed-price plan keeps the energy rate stated in its Electricity Facts Label for the contract term; variable and indexed plans follow their own terms. Retail offers are set by each provider and were not measured in this report.
Comparing offers: Compare each retailer's actual all-in price on its Electricity Facts Label at 500, 1,000 and 2,000 kWh, because a bill credit can make a plan look cheap at one usage level and costly at another. Today's research does not establish a verified movement in those published retail offers; the direction above is a market outlook, not a measured retail-rate change.
Commercial pricing: index and block contracts pass wholesale swings through faster than fixed-price contracts.
For a new fixed contract: Tuesday’s West day-ahead average jumped $47.10/MWh from Monday, and the quoted evening hour reached $201.90/MWh. But suppliers price a six-, twelve- or twenty-four-month contract using an entire future delivery period—not just one Tuesday. The older October 29 calendar-2027 Houston and North forward marks actually eased by $0.13 and $0.24/MWh from October 28. That is a dated wholesale forward comparison; no commercial quotes were collected for this report. [26] [1]
For an index contract: The customer pays a market-linked rate that can change by the hour or settlement interval. That makes the West overnight move directly relevant: official West load-zone prices exceeded North by $46.75/MWh at 7:30 a.m., then only $4.28/MWh at 8:00 a.m. An index buyer’s exposure depends on the named pricing location, contract formula, and the business’s actual electricity use during those intervals. [9]
For block-and-index: A business purchases a set amount of electricity at a fixed price (the “block”) and pays or receives market pricing on the difference between that block and actual consumption. The key question is which hours and which settlement point are actually protected. [26]
Brokers: translate a price shock into better comparisons, not a prediction of tomorrow’s offers.
For residential clients, the honest interpretation is that a reported West day-ahead rise of $47.10/MWh is a reason to monitor new offers—not to tell customers their next bill is about to rise. A conventional fixed plan does not reprice in response to an intraday spot move. Compare real Electricity Facts Labels at 500, 1,000 and 2,000 kWh, including bill-credit thresholds, before claiming one retailer beats another. [26]
For commercial clients, first establish whether the buyer wants stability or accepts market swings. The official $27.81/MWh West load-zone premium over West Hub at 7:30 a.m. is a tangible example of why a cheap-looking hub-indexed quote can behave differently from the customer's billed load-zone price. Ask which location sets the rate, how many MW are fixed, which hours are covered, and how any unmatched consumption is settled. [9]
Why details matter: Vistra’s dated calendar-2027 Houston–North forward difference was only $1.81/MWh. That is a dated forward-market difference, not a quote difference or commission. A broker adds value by checking that supplier bids use the same dates, volumes, fees and delivery terms before making a cost comparison. [1]
Investors: a large intraday spread, but not evidence of realized storage profits.
What stands out: West’s day-ahead price was just $0.80/MWh during 10–11 a.m. and $201.90/MWh during 10–11 p.m.. This $201.10/MWh separation is the kind of intraday spread that storage and flexible-generation operators watch. The high hour was still ahead of us at the 8 a.m. cutoff. ERCOT's official Nov 3 DAM file confirms West HE11 $0.82 and HE23 $201.92. [26]
Caveat: Actual storage outcomes depend on when a battery charged, where it was located, its market awards, fees, losses and battery wear. A price spread on paper is not proof of an investor return or a trading opportunity available after the fact.
The wider backdrop is mixed: The latest EIA release recorded +80 Bcf of U.S. gas storage, 8 Bcf above one cited expectation, while South Central storage remained 28 Bcf below its five-year norm. CFTC positioning showed NYMEX gas managers net short 206,317 contracts as of October 27. These are useful signals about fuel supply and sentiment, not a reliable next-day forecast for power prices or energy stocks. [23] [3] [24]
A high wholesale hour does not automatically become a higher fixed-rate offer.
Think of three price clocks running at different speeds. Real-time electricity can move every 15 minutes. Day-ahead electricity is priced one day before delivery. New retail and commercial fixed contracts are generally based on expected purchases across months or years. A dramatic number on one clock does not automatically move the others.
West’s 7:30 a.m. real-time load-zone premium over North reached $46.75/MWh, and its evening day-ahead hour was $201.90/MWh. These matter most to index exposure and to the unhedged portion of block-and-index contracts. [9] [26]
Retail and commercial quotes were not measured in this report. The Oct 29 supplier forward marks and the Tuesday peak-load forecast are shown above for context only. [1] [5] [25]
Several days of similarly expensive peak hours, a sustained increase in forward prices, or repeated West-specific congestion. This report has not measured retail offers or Electricity Facts Label prices.
What would change this outlook after 8 a.m.?
Sources & references · 31 accessible destinations.
Only accessible source pages, directly reviewed tables, original reports and usable context documents appear below. Inaccessible feeds, blocked pages, placeholder URLs and unparsed data endpoints have been omitted. Each entry records observation or release dates wherever established; secondary-source price figures are shown beside ERCOT's official files.
| # | Source and direct evidence | Access / currency |
|---|---|---|
| 01 | Vistra ERCOT weekly Underlying document Page 1: Cal27/Cal29 hubs and Oct zone prices; p2: gas & NOAA outlook; p3 commentary | READ · PDF Weekly · week ended 30 Oct; published/hosted 2 Nov |
| 02 | Constellation commodity weekly November $2.60 on 26 Oct; production ~110 Bcf/d and 2027–31 futures strips | READ · page Weekly · 26 Oct |
| 03 | NRG daily market updates 2 Nov summary; 30 Oct storage estimate compared with actual | READ · page Business days · most recent 2 Nov morning |
| 04 | ENGIE pricing data Dec NG $2.888, prior settle $2.856; source percentage label inconsistent | READ · table Daily/live · 3 Nov gas; ERCOT spot 02:15 |
| 05 | NextEra Energy Pulse Underlying document PDF p1: Cal26 ERCOT $39.33 (−$2.43); Cal26 gas $2.99 (−$0.26) | READ · PDF Biweekly · 28 Oct |
| 06 | ERCOT transmission No named 3 Nov binding constraint or shadow price verified | READ · context Events / publications |
| 07 | ERCOT grid dashboards index Source navigation, not an independent data point | READ · index Live |
| 08 | ERCOT market prices Verified distinctions between DAM, RTM SPP and 5-min LMP | READ · index Daily / 15-min |
| 09 | ERCOT real-time SPP 32 intervals × eight selected hubs/zones transcribed and calculated; last interval ends 08:00 | READ · 32 rows 15-min · 3 Nov 00:15–08:00; display updated 08:02 |
| 10 | Calpine Energy Solutions Weekly update index accessible; no new 3 Nov figures | READ · index Weekly / ad hoc |
| 11 | RWE investor relations 11 Nov earnings expected; 3 Nov Germany generation announcement (time unverified) | READ · index Quarterly / ad hoc |
| 12 | CFTC COT home Latest positioning observed Tue 27 Oct, released Fri 30 Oct | READ · index Weekly · Tues obs, Friday release |
| 13 | OilPriceAPI Waha Waha $1.46 30 Oct; matched Waha minus EIA HH −$1.35 on 27 Oct | READ · dated table Weekday · Waha spot 30 Oct; paired basis 27 Oct |
| 14 | ERCOT realtime conditions Not used in as-of 08:00 metrics | READ · POST-CUTOFF Live · display at 08:11:40 Nov3 |
| 15 | ERCOT operations messages No specific 3 Nov shadow-price cause established | READ · index Event-driven |
| 16 | ERCOT system planning Project planning context; not 08:00 reserve readout | READ · index Planning |
| 17 | ERCOT NPRRs No price effect ascribed without a dated adopted NPRR | READ · index Issue-driven |
| 18 | CFTC weekly disaggregated TXT Underlying document Managed money ICE LD1 longs/shorts and weekly changes verified | READ · raw CSV-style Weekly · obs 27 Oct, released 30 Oct |
| 19 | Open-Meteo weather API Specific 08:00 Texas forecast not queried with reproducible model vintage | READ · docs Model cycles 1–6h |
| 20 | Gridstatus ERCOT API examples Lists 7-day MTLF and hourly outage API endpoint IDs; not live data | READ · docs Versioned reference |
| 21 | NOAA SWPC K-index JSON Kp 1.67 at 09:00 UTC (03:00 CST), low immediate grid-weather materiality | READ · JSON 3h · Nov3 09:00 UTC observed |
| 22 | USGS Water Services No hydro/thermal-cooling site data extracted; announced decommission Feb 2027 | READ · documentation Station dependent |
| 23 | EIA Weekly Natural Gas Storage report Table 1: U.S. 3,724 Bcf (+80), South Central 1,168 Bcf (+43), salt 274 (+23) | READ · numeric table Weekly · released 29 Oct, observed week ended 23 Oct |
| 24 | CFTC Natural Gas disaggregated short report NYMEX net −206,317 (weekly −48,908); ICE LD1 net +49,145 (weekly −81,943) | READ · numeric tables Weekly · observed 27 Oct |
| 25 | GridVigil ERCOT derived load outlook Five next-day daily peaks available; projected reserve 18.29% model, NOT operating reserve | READ · data Vintage as of Nov2 · snapshot 20:47 UTC |
| 26 | Selectra ERCOT day-ahead republication Selectra republication; matches ERCOT's official DAM files to rounding. | READ · secondary data Hourly DAM · published by source 2 Nov 13:02 CT |
| 27 | AskTheGrid West RT historical Nov2 West hub 5-minute real-time LMP mean $12.50, low −$7.03, high $71.82 (Ask the Grid's LMP series, not RT SPP; ERCOT's 15-minute SPP West Hub mean is $12.74) | READ · secondary Daily · Nov2 completed |
| 28 | USFast DFW weather 08:00 65°F forecast WNW 10mph; daytime ~72°F | READ · hourly forecast Updated Nov3 00:26 CT |
| 29 | ERCOT DAM settlement point prices, Nov 3 2026 24 hourly prices; West LZ mean $65.01, North $51.95, Houston $68.31, South $66.97; West LZ low $0.82 (HE11), high $201.92 (HE23); West Hub mean $57.41 | READ · official ERCOT file Hourly DAM · delivery day Nov 3 |
| 30 | ERCOT DAM settlement point prices, Nov 2 2026 24 hourly prices; West LZ mean $17.86, North $26.19, Houston $40.26, South $33.01; West Hub mean $14.47 | READ · official ERCOT file Hourly DAM · delivery day Nov 2 |
| 31 | ERCOT real-time settlement point prices, Nov 2 2026 96 15-minute intervals; West Hub mean $12.74, West LZ mean $16.22 (our calculation) | READ · official ERCOT file 15-minute SPP · full day Nov 2 |
Coverage is curated to accessible primary market reports and usable secondary evidence. Figures are labeled by settlement or observation date; historical comparisons are shown only when matched on measure and timing. ERCOT's API Explorer/portal require an accessible session for many reports; the data are not deemed verified merely because a link was supplied.