Yesterday's price pressure. Today's West Texas premium.
November 3 was a volatile trading day. The next day's day-ahead auction still prices West Texas higher than North Texas, and fresh overnight settlement data confirm a sizable West Texas load-zone premium—but it narrowed substantially by 8 a.m. Index and block contracts pass wholesale swings through faster than fixed-price contracts.
Data cutoff 08:00 America/Chicago • All timestamps CST • Hub prices = wholesale $/MWh • ERCOT settlement, day-ahead and forecast files read directly • Third-party figures labeled.
Six signals worth watching this morning
Yesterday realized versus today scheduled
November 3 real-time, 5-minute LMP
Equal-weighted means of the 290 five-minute LMP runs ERCOT posted for Nov 3 (ERCOT report NP6-788-CD). ERCOT's 15-minute settlement-point prices for the same day average Houston $50.00, North $38.92 and West $49.11. Ask the Grid (a third-party site) reported Houston $50.37, North $39.78 and West $49.25 (partial, through 22:35 CST); the first two equal ERCOT's 5-minute means above, and ERCOT's own West mean through 22:35 CST is also $49.25. These are 5-minute LMP means, not 15-minute SPP settlement prices. [22, 24]
November 4 delivery, 24-hour DAM averages
ERCOT posted this day-ahead file on Nov 3 at 12:36 CST, well before today's 08:00 cutoff. Values are 24-hour arithmetic means of ERCOT's hourly hub prices for Nov 4 delivery. [21]
November 4 day-ahead hub prices
24-hour average, $/MWh; ERCOT day-ahead file posted Nov 3 12:36 CST [21]
Basis: West is $13.30/MWh higher than North; Houston is $7.84/MWh higher than North; South is $7.45/MWh higher than North. West vs Houston: +$5.46/MWh. Regional price differences still matter even when ERCOT's overall demand outlook is moderate.
The real-time West premium: a steep overnight slide
ERCOT real-time trading-hub SPP • Nov 4, 00:15–08:00 CST
Actual 15-minute settlement point prices, $/MWh. All 32 published rows read from ERCOT's table; this chart deliberately ends at the requested 8 a.m. cutoff. [1]
$62.72 /MWh
West hub partial 00:15–08:00 mean; equal weight per 15-min interval (32 rows).
$79.93 /MWh
West load-zone partial mean over same 32 settlement intervals; not a day-average.
West load-zone SPP rose as high as $97.90/MWh at 01:45, versus North load-zone $32.60/MWh then, a $65.30/MWh local premium. At 08:00 West load-zone had declined to $28.00/MWh and North to $14.17/MWh, a remaining $13.83/MWh premium. The exact transmission constraint behind that premium has not been proven from the available shadow-price records. [1]
Why West hub and West load-zone differ
Trading hubs average selected grid nodes. A load zone reflects where buyers actually use electricity. At 01:45, West load-zone SPP was $97.90 while West Hub was $74.03—a $23.87/MWh difference. Those are different settlement points, not alternative quotes for the same delivery location.
Transmission constraints are a hypothesis, not a finding
Large regional separation is consistent with congestion or localized grid conditions, but a credible physical cause requires same-interval binding-constraint identity, shadow price, network topology and outage records. Planned maintenance, renewable ramps and Permian industrial load are plausible hypotheses, not verified November 4 causes.
Demand, grid supply and the next seven days
ERCOT expected system peak demand: November 4–10
GW, separately published operator load-forecast vintages; Nov 4 forecast from Nov 3 23:30 CST, later dates from Nov 4 02:30 CST. 24 hourly forecast intervals available each day. These are ERCOT's own forecast files (report NP3-560-CD); the Nov 4 02:30 run puts today's peak at 56.71 GW. [6, 23]
Today's expected peak is 56.4 GW in the 3–4 p.m. hour Thursday is higher at 58.90 GW (up 2.50 GW versus today's 23:30 figure; 2.19 GW within the 02:30 run), while the weekend trough falls to 51.30 GW Sunday. More demand generally raises the cost of serving peak hours, but it is only one ingredient: actual wind, solar, thermal outages and transmission restrictions may dominate localized prices.
What the renewable and outage feeds add
ERCOT's dedicated generation outage, storage-resource, supply-demand and fuel-mix JSON endpoints were inspected. They are useful operational sources, but a time-matched numerical series was not extractable with sufficient confidence for this 08:00 edition. Therefore no MW outage, reserve cushion, battery charge/discharge, or net-load value is invented. [17–20]
The ordinary ERCOT system-conditions table was updated after the 08:00 cutoff; its numbers are deliberately excluded. [3]
Other reliability signals
The NOAA three-hourly planetary geomagnetic K-index was 3.33 at 06:00 UTC on Nov 4 (midnight CST), below the Kp 5 minor geomagnetic storm threshold. That does not establish whether any ERCOT GMD limits applied. [15]
ERCOT operations notices provide context, but no current notice was verified here as proving a direct physical cause of the West load-zone premium. [16]
Natural gas, storage and positioning
December gas: Nov 3 settle (press report)
$2.895/MMBtu
December NYMEX natural gas settled at $2.895/MMBtu on Nov 3, as reported by Dow Jones [14]: a press report of the NYMEX settlement, not a CME page. A later quote and the week-over-week and one-month changes in a third-party quote page could not be checked against CME or another primary source and are not used here. Unlike a 15-minute regional price spike, a sustained gas-price move can feed into longer-dated thermal generation economics. These are delayed informational quotes, not executable supplier electricity quotes. [14]
The South Central region drove the injection
+43 Bcf / +80 Bcf
EIA's Oct 29 release, for the week ending Oct 23, reported +80 Bcf nationally and +43 Bcf in South Central storage—about 54% of the net national increase. US working gas total stood at 3,724 Bcf, 38 Bcf above the five-year average. The next weekly report is due Nov 5; do not treat this as a new Nov 4 observation. [10–12]
Positioning risk
Friday's last available CFTC disaggregated release covers Tuesday October 27 positions, not current-day trades. A third-party quote page's futures report and related dated quote summary show managed money heavily net short natural gas (about 206,000 contracts net short in the NYMEX natural gas series: 405,217 short minus 198,900 long in the CFTC file). That means a rising gas market could produce short-covering, but neither its timing nor the direction of prices is established. The exact contract definition matters when reconciling different CFTC series. [13–14]
Four audience perspectives · the real-world implications
Residential electricity consumers
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. The widest wholesale price gap in this edition was in West Texas: the overnight load-zone SPP peaked at $97.90/MWh and fell to $28.00 by 8 a.m. [1]
Day-ahead hub averages for Nov 4 differ by region. The North hub average of $35.36/MWh is below its seven-day day-ahead average of $36.91/MWh (Oct 29–Nov 4 delivery days, today included); West, at $48.66, is above its seven-day average of $40.43. Retail plan prices depend on ZIP code, usage and contract terms. Each plan's Electricity Facts Label (EFL) lists its price at 500, 1,000 and 2,000 kWh, and Power to Choose, the PUCT's plan-comparison website, lists plans that retail electric providers choose to post. No current retail Electricity Facts Labels were collected for this report. [5, 21]
Commercial electricity buyers
Where the price is set: A fixed-price offer for a future period depends mainly on forward prices for those months, not on one morning's settlement peak. The November 4 day-ahead hub averages range from $35.36/MWh North to $48.66/MWh West, which shows that location matters; they are not supplier quotes for future contracts. No commercial quotes were collected for this report. [5, 21]
How do index and block pricing react? An index contract passes through more near-term grid-price movement. A block-and-index contract fixes a chosen portion of consumption and leaves the rest exposed. For an index buyer, the settlement point matters: at 01:45 the West load-zone price was $65.30/MWh above the North load-zone price. A fixed-price hedge covering the same location and hours could shield some risk. [1]
Electricity brokers
A big wholesale number is not a retail rate. The Nov 4 day-ahead West-minus-North hub spread is $13.30/MWh, while the more granular early-morning West-minus-North load-zone spread briefly reached $65.30/MWh. These are different products, and neither is a long-term price quote. [1,5]
One day's natural-gas settle cannot by itself quantify a customer's rate change. [14]
Investors, generators and storage developers
West Texas still has a volatility story, not an automatic battery investment case. At 01:45 the West load-zone SPP was $97.90/MWh compared with $32.60 in North, but by 8 a.m. West had fallen to $28.00. A 100-MW battery cannot be valued by multiplying a single fifteen-minute spread by a year; it may not be charged, connected or dispatched at the favorable node. [1]
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. Site screening needs actual nodal hourly spreads, future battery competition, outage and constraint duration, available interconnection capacity, curtailment rules and maintenance upgrades. [1]
Risks and watchlist
Local West Texas congestion
Track West load-zone against West hub, North hub and active binding SCED constraints. The overnight $23.87/MWh West load-zone-versus-hub difference at 01:45 is a more useful research question than a broad grid-wide alarm. Shadow prices and outages are needed before attributing cause.
Gas and operating reserve changes
Watch Thursday's Nov 5 EIA storage release, fresh gas futures, thermal outages and ancillary-price clearing. An unconfirmed public JSON value is not a valid reserve calculation. Separately monitor the 58.90 GW Thursday forecast versus today's 56.40 GW outlook.
Sources & references
Accessible direct sources and working data pages checked for this research. Dates indicate data observation and publication where established. All links are clickable. Blocked, missing, date-placeholder and inaccessible landing pages are excluded. Some operational JSON feeds could be opened but did not yield a trustworthy time-scoped numerical table; those are explicitly labeled and not represented as numeric evidence.
- ERCOT real-time SPP — Nov 4 00:15–08:00 CST
15-minute settlement point prices; directly read 32 official rows; as of 08:00 CST.
- ERCOT 5-minute hub/load-zone LMP
Five-minute LMP display; different from 15-minute SPP.
- ERCOT real-time system conditions
Live table accessed, but its update falls after the cutoff and is excluded.
- ERCOT load forecast versus actual
Chart page last updated earlier in the morning; underlying image lacks extractable numerical points.
- Compute Screener — ERCOT November 4 DAM
Third-party republication of the Nov 4 day-ahead hub averages; matches ERCOT's official file (source 21) exactly.
- Ask the Grid — seven-day load forecast
Third-party republication of ERCOT's seven-day forecast (vintages Nov 3 23:30 for Nov 4, Nov 4 02:30 for Nov 5–10); matches ERCOT's files (source 23) to rounding.
- Ask the Grid — Houston real-time LMP
Reported a Nov 3 mean of $50.37/MWh (5-minute LMP); ERCOT's own files (source 22) give the same, $50.37.
- Ask the Grid — North real-time LMP
Reported a Nov 3 mean of $39.78/MWh (5-minute LMP); ERCOT's own files (source 22) give the same, $39.78.
- Ask the Grid — West real-time LMP
Reported a partial Nov 3 mean of $49.25/MWh (through 22:35 CST); ERCOT's files (source 22) give $49.25 for the same window and $50.16 for the full day.
- EIA Weekly Natural Gas Storage Report
Released October 29; stocks as of October 23: 3,724 Bcf, +80 Bcf.
- EIA South Central storage weekly series
South Central 1,168 Bcf as of Oct 23; weekly change +43 Bcf.
- EIA storage JSON
Direct JSON body read; release Oct 29; storage week ending Oct 23.
- CFTC disaggregated futures positions
Direct source text opened; positions as of Tuesday Oct 27, weekly not daily. NYMEX natural gas, managed money: 198,900 long, 405,217 short.
- Dow Jones via Morningstar: front-month Nymex natural gas settle, Nov 3
Reports the December contract settling at $2.8950/MMBtu on Nov 3; a press report of the NYMEX settlement, not a CME page.
- NOAA space weather Kp observations
JSON 3-hour observations; Nov 4 06:00 UTC Kp 3.33, 09:00 UTC 2.33.
- ERCOT operations messages
Public notice page accessed; no independently verified current constraint attribution.
- ERCOT daily generation outages JSON
JSON endpoint accessible; numerical body was not extracted into reliable date-scoped series.
- ERCOT storage resource JSON
JSON endpoint accessible; time-stamped MW values not independently extracted.
- ERCOT supply/demand JSON
JSON endpoint accessible; not used for invented reserve figures.
- ERCOT fuel mix JSON
JSON endpoint accessible; numeric payload not sufficiently extracted for morning cutoff.
- ERCOT day-ahead market settlement point prices, Nov 4 2026
Official ERCOT file posted Nov 3 12:36 CST; 24 hourly prices per hub. Hub means: North $35.36, Houston $43.20, South $42.81, West $48.66. Seven-day means use ERCOT's day-ahead files for Oct 29–Nov 4 delivery days.
- ERCOT LMPs by resource nodes, load zones and trading hubs (NP6-788-CD)
Five-minute LMP files for Nov 3 (290 runs); equal-weighted means: Houston $50.37, North $39.78, West $50.16.
- ERCOT seven-day load forecast by forecast zone (NP3-560-CD)
Runs of Nov 3 23:30 and Nov 4 02:30; daily peak is the highest hourly system-total value.
- ERCOT real-time settlement point prices, Nov 3 2026
96 fifteen-minute intervals; hub means: Houston $50.00, North $38.92, West $49.11.