Yesterday, West exploded.
Today, the South carries the premium.
October 31's West Hub five-minute real-time price averaged $86.77/MWh, more than $35 above North. But the already-cleared November 1 day-ahead auction puts South highest at $36.65/MWh while West falls toward $5/MWh by the final hour. The clock change creates 25 delivery hours—and a data-quality trap.
Five numbers that change the story.
Prices in $/MWh unless otherwise specified. Source and observation dates matter.
Yesterday → today, two different price stories.
Yesterday's West premium
West $86.77 vs North $51.14 full-day five-minute LMP mean. Houston averaged $55.93. Versus Oct 30, West rose $51.12, Houston $21.33, North $16.86 per MWh. These are verified comparable secondary 5-min LMP daily series—not ERCOT settlement prices. [21][22][23]
Yesterday's daily single-interval West high in the same mirror was $248.24/MWh; do not confuse it with the full-day mean. [23]
Today's 25-hour day-ahead averages
South leads; Houston $34.48, West $29.17, North $29.00. The South–North average spread is +$7.65/MWh; Houston–North +$5.48; West–North only +$0.17. All are arithmetic means of the 25 published hourly settlement points. [14]
These day-ahead prices were auctioned Oct 31 (14:22 CDT publication). They are not real-time prices and are not a direct realized day-over-day comparison. [14]
November 1 day-ahead hub curves
HE14; South $34.29, North $16.31. [14]
HE13; Houston $30.27, North $14.98. [14]
HE24; West vs North $18.66. No negative-price claim. [14]
Show all 25 day-ahead hourly hub prices
| Hour ending | North | Houston | South | West | South−North |
|---|---|---|---|---|---|
| HE 1 | $51.44 | $52.81 | $55.92 | $62.02 | $+4.48 |
| HE 2 | $46.72 | $47.72 | $49.92 | $54.71 | $+3.20 |
| HE 2* | $39.50 | $40.51 | $42.24 | $46.40 | $+2.74 |
| HE 3 | $38.69 | $39.54 | $41.72 | $45.97 | $+3.03 |
| HE 4 | $37.71 | $37.95 | $40.74 | $43.82 | $+3.03 |
| HE 5 | $36.17 | $36.15 | $39.01 | $41.47 | $+2.84 |
| HE 6 | $38.20 | $37.96 | $40.80 | $42.62 | $+2.60 |
| HE 7 | $34.08 | $33.92 | $36.17 | $37.57 | $+2.09 |
| HE 8 | $28.62 | $28.20 | $30.87 | $31.42 | $+2.25 |
| HE 9 | $21.38 | $21.85 | $25.59 | $24.40 | $+4.21 |
| HE 10 | $17.81 | $22.76 | $26.38 | $21.22 | $+8.57 |
| HE 11 | $17.32 | $24.07 | $27.20 | $19.93 | $+9.88 |
| HE 12 | $14.71 | $25.46 | $28.68 | $17.80 | $+13.97 |
| HE 13 | $14.98 | $30.27 | $32.23 | $17.99 | $+17.25 |
| HE 14 | $16.31 | $31.00 | $34.29 | $17.65 | $+17.98 |
| HE 15 | $19.89 | $33.88 | $36.91 | $20.37 | $+17.02 |
| HE 16 | $23.68 | $36.95 | $41.30 | $23.57 | $+17.62 |
| HE 17 | $35.32 | $43.16 | $48.15 | $34.34 | $+12.83 |
| HE 18 | $40.40 | $46.12 | $49.74 | $38.46 | $+9.34 |
| HE 19 | $35.51 | $38.84 | $40.19 | $31.52 | $+4.68 |
| HE 20 | $31.48 | $36.51 | $37.92 | $24.35 | $+6.44 |
| HE 21 | $25.03 | $32.49 | $31.46 | $12.93 | $+6.43 |
| HE 22 | $20.53 | $31.63 | $29.52 | $6.88 | $+8.99 |
| HE 23 | $20.83 | $28.50 | $27.15 | $6.57 | $+6.32 |
| HE 24 | $18.66 | $23.72 | $22.14 | $5.18 | $+3.48 |
HE2* is the repeated clock hour after daylight saving time ended. The ERCOT default DAM page currently says the next auction is pending; an indexed snapshot of the official primary page exposed the already-published Nov 1 25-row table. Direct page re-open was inconsistent. [14]
Real-time settlement at the morning cutoff
At 08:00 CST Houston $33.12, North $30.85, South $30.22 and West $30.73/MWh; Houston–North +$2.27. Earlier at 02:15 CST, West reached $68.61 while North was $49.26, a +$19.35 interval basis. West load zone at 02:15 was $80.16—+$11.55 over West Hub. This is location risk, not a daily average. [13]
| 15-min ending | Houston | North | South | West | West−North |
|---|---|---|---|---|---|
| 00:15 | $48.18 | $47.45 | $50.03 | $55.72 | $+8.27 |
| 01:15 | $59.22 | $59.06 | $59.42 | $60.04 | $+0.98 |
| 01:15* | $44.33 | $43.42 | $44.47 | $43.95 | $+0.53 |
| 02:15 | $51.59 | $49.26 | $57.33 | $68.61 | $+19.35 |
| 03:15 | $47.92 | $47.11 | $48.95 | $52.06 | $+4.95 |
| 04:15 | $42.83 | $42.83 | $42.83 | $42.83 | $+0.00 |
| 06:15 | $53.28 | $53.28 | $53.28 | $53.28 | $+0.00 |
| 07:45 | $32.98 | $30.76 | $30.16 | $30.65 | $-0.11 |
| 08:00 | $33.12 | $30.85 | $30.22 | $30.73 | $-0.12 |
Source last updated 08:02 CST, two minutes after the 08:00 observation cutoff. Asterisk denotes repeated 01:00 hour. Source's SPP includes ERCOT reliability deployment adders. [13]
Monday is the demand watch.
Daily projected system peaks
Today 61.72 GW vs yesterday's completed 59.795 GW observed peak: +1.92 GW, +3.2% (forecast vs realized, not like-for-like). Monday's 64.44 GW forecast is +2.72 GW (+4.4%) above Sunday's forecast. [20]
Ask the Grid's ERCOT-derived seven-day forecast (Nov 1 06:30 CST run; Sunday from the Oct 31 23:30 CDT run) puts daily peaks between 64.44 GW on Mon Nov 2 and 52.06 GW on Sat Nov 7. [20]
Reserves and outage MW are not verified.
ERCOT's supply/demand and generation-outage dashboards expose only static text or “Loading…” in this retrieval. The grid-conditions endpoint returned 403. No current reserve margin, reserve MW or forced outage total is asserted. An advisory-like third-party operator status is not proof of an emergency. [6][10][11]
Weather's load effect
Houston's Nov 1–2 highs are forecast in the low 80s °F, followed by a Tuesday front and increased rain chances. This is a weather forecast, not a measured power price. With the 64.44-GW Monday load peak, weather-sensitive afternoon demand deserves attention. [26][20]
The third-party demand mirror displayed a spurious 97.68-GW “record” at 01:00 on the DST changeover while its actual daily peak table showed 48.84 GW so far. The former is rejected as a clock/aggregation anomaly, not reported as a real record. [20]
Transmission / congestion
Today's South–North DAM premium +$7.65/MWh is measurable basis, but it does not establish which constraint caused it. The official current shadow-price report was inaccessible. Older Oct 22 third-party observations recorded BLESSING 1382 at $1,104/MWh shadow price; Oct 20 CONCHO HARI1 A at $2,503/MWh. These are historical examples, not Nov 1 conditions. [14][8][36]
Soft prompt gas. More nuanced power curve.
December 2026 Henry Hub
$/MMBtu in ENGIE's Nov 1 table; prior settle $2.952 and displayed change −$0.054. The table labels a Sunday update, but exchanges are closed: treat it as a carried forward/indicative snapshot, not a Sunday executable trade. [4]
Gas inventories
Week ended Oct 23: +80 Bcf, vs 3,644 prior week; +38 Bcf (+1.0%) above five-year average and −147 Bcf (−3.8%) below year ago. South Central injected +43 Bcf and remained −2.3% vs its five-year norm. [19]
Gas price comparison
*Different gas tenors are shown for market context, not a comparable time series: Cal26 annual strip versus December monthly futures. Oct 30 morning NRG indication was $2.85; Nov 1 ENGIE snapshot $2.898. [3][4][30]
What the supplier reports disagree on
Constellation (Oct 26) lists NYMEX Cal27–31 at $3.00, $3.63, $3.66, $3.65, $3.61/MMBtu. Vistra's Oct 23 landing says Cal27 power eased while Cal28–30 strengthened. Its linked “full report,” however, is dated Oct 9, with Houston Cal27 $48.67 and Cal29 $55.61/MWh as of Oct 8 (PDF p.1). Do not treat that PDF as an Oct 23 quote. [2][1][29]
Calpine (Oct 29 PDF p.1) describes term gas down $0.10–$0.15/MMBtu over its Oct 22–28 comparison. [32]
Weekly positioning is not a daily signal.
NYMEX natural gas: managed money net short
Contracts: long 198,900 minus short 405,217; prior week net −157,409, so net short expanded 48,908 contracts. NYMEX natural gas #023651, 10,000 MMBtu per contract; this is positions, not a gas price forecast. [34]
ERCOT North RT peak: managed money net long
ICE #06439R: long 63,277, short 5,245. Weekly net change −4,489 contracts (long −3,904; short +585). Contract definitions and peak-hour exposures matter; not directly comparable to gas lots. [35]
Generator strategy
RWE's August 2026 Factbook (pp. 20–21) details 15 flexible-gas projects totaling approximately 5 GW in development, targeting 3+ GW execution by 2035 across ERCOT, MISO, PJM and WECC. Factbook pp. 78–83 explains storage revenue from intraday spreads, grid services and capacity; these are strategic plans, not operating assets today. [33]
Regulatory / infrastructure watch
CFTC's current weekly page lists newly reported Nodal Exchange ERCOT South and West on/off-peak contracts. A newly reported contract is not evidence of new physical capacity. ERCOT's Batch Zero framework covers requests ≥75 MW; the August/September data-center impact RFI targeted ≥25 MW projects with a Dec 10 report target. [17][27][28]
Retail comparisons: evidence before headline rates.
Retail plan prices change daily and depend on ZIP code, usage and contract terms. This report does not list retail plans or prices. To compare current plans, use each plan's Electricity Facts Label (EFL) or the PUCT's Power to Choose website, powertochoose.org.
Four audiences. Specific numbers. Real trade-offs.
A $51/MWh wholesale jump does not reprice your fixed contract overnight.
Southern load shape and zone basis matter more than a statewide average.
- Measured: Nov 1 South–North DAM average basis +$7.65/MWh; at HE14 it widens to +$17.98. Illustration: 10 MWh delivered at that HE14 difference represents $179.80 in location-price difference before contractual adjustments. [14]
- Measured: Nov 2 peak forecast 64.44 GW, +2.72 GW over Sunday forecast. Context: product types (fixed, indexed, block-plus-index) can carry different load-zone and interval exposure. [20]
Show both the spike and the curve reversal.
Scarcity and storage are conditional, not automatic profits.
Three things that could change the call.
18-source audit. No phantom downloads.
READ = report content or numerical table reviewed. PARTIAL = landing or some data reviewed but a needed report/table inaccessible. BLOCKED = numerical source unreadable. All sources listed in full below.
| # | Source | Status | What was actually accessible / freshness |
|---|---|---|---|
| 01 | Vistra ERCOT Weekly | PARTIAL | Landing dated Oct 23; linked PDF dated Oct 9; both read. Weekly; PDF is older than landing. |
| 02 | Constellation Energy Market Update | READ | Oct 26 weekly commentary read; dated gas and 2027–31 strip figures. |
| 03 | NRG Daily Market Updates | READ | Oct 30 daily note and Oct 26–29 history read; latest pre-Sunday publication. |
| 04 | ENGIE Today’s Pricing Data | READ | Nov 1 snapshots (ERCOT 06:45 CST; Henry Hub table Nov 1); values indicative, Sunday markets closed. |
| 05 | NextEra Energy Pulse | READ | Oct 28 and Oct 14 biweekly PDFs read; two-week Cal26 comparisons. |
| 06 | ERCOT Grid Conditions | BLOCKED | 403 denied; no verified reserve MW / reserve margin. |
| 07 | ERCOT Load | PARTIAL | Load landing and MTLF explanatory page read; seven-day numbers via ERCOT-derived mirror. |
| 08 | ERCOT Transmission | BLOCKED | 403 denied; no current official shadow-price table read. |
| 09 | ERCOT Dashboards Index | PARTIAL | Dashboard index read; live interactive data not exposed as numeric text. |
| 10 | ERCOT Supply and Demand | PARTIAL | Static page read; live capacity/reserve chart inaccessible. |
| 11 | ERCOT Generation Outages | PARTIAL | Static page read; live MW widget says Loading; current outage totals unverified. |
| 12 | ERCOT Market Prices | PARTIAL | Price report landing read; no numeric time series in landing. |
| 13 | ERCOT Real-Time SPP | READ | Nov 1 00:15–08:00 CST 15-minute settlement rows read; last updated 08:02. |
| 14 | ERCOT Day-Ahead SPP | PARTIAL | Nov 1 25-hour delivery table read via indexed primary page (published Oct 31 14:22); direct open erroneously displays new auction pending. |
| 15 | Calpine Solutions Weekly | READ | Oct 29 1-page PDF read, covering Oct 22–28; gas/storage and regional trends. |
| 16 | RWE Investor Relations | READ | Aug 2026 Factbook 118-page PDF read, especially pp. 20–21 and 78–83; not a daily price feed. |
| 17 | CFTC COT Index | READ | Oct 27 Tuesday positions, released Oct 30 Friday; direct gas and electricity reports read. |
| 18 | CFTC Public Reporting Environment | BLOCKED | Page renders without readable tabular content; direct CFTC static reports used instead. |
Every report, underlying PDF and data source.
Numbered links include all 18 required sources, their direct report links where available, and additional primary/mirror sources. No downloaded archive or spreadsheet is required. As-of Nov 1 08:00 CST; linked dynamic pages may have updated since capture.
- 01Vistra ERCOT Weekly ↗
Landing dated Oct 23; linked PDF dated Oct 9; both read. Weekly; PDF is older than landing.
- 02Constellation Energy Market Update ↗
Oct 26 weekly commentary read; dated gas and 2027–31 strip figures.
- 03NRG Daily Market Updates ↗
Oct 30 daily note and Oct 26–29 history read; latest pre-Sunday publication.
- 04ENGIE Today’s Pricing Data ↗
Nov 1 snapshots (ERCOT 06:45 CST; Henry Hub table Nov 1); values indicative, Sunday markets closed.
- 05NextEra Energy Pulse ↗
Oct 28 and Oct 14 biweekly PDFs read; two-week Cal26 comparisons.
- 06ERCOT Grid Conditions ↗
403 denied; no verified reserve MW / reserve margin.
- 07ERCOT Load ↗
Load landing and MTLF explanatory page read; seven-day numbers via ERCOT-derived mirror.
- 08ERCOT Transmission ↗
403 denied; no current official shadow-price table read.
- 09ERCOT Dashboards Index ↗
Dashboard index read; live interactive data not exposed as numeric text.
- 10ERCOT Supply and Demand ↗
Static page read; live capacity/reserve chart inaccessible.
- 11ERCOT Generation Outages ↗
Static page read; live MW widget says Loading; current outage totals unverified.
- 12ERCOT Market Prices ↗
Price report landing read; no numeric time series in landing.
- 13ERCOT Real-Time SPP ↗
Nov 1 00:15–08:00 CST 15-minute settlement rows read; last updated 08:02.
- 14ERCOT Day-Ahead SPP ↗
Nov 1 25-hour delivery table read via indexed primary page (published Oct 31 14:22); direct open erroneously displays new auction pending.
- 15Calpine Solutions Weekly ↗
Oct 29 1-page PDF read, covering Oct 22–28; gas/storage and regional trends.
- 16RWE Investor Relations ↗
Aug 2026 Factbook 118-page PDF read, especially pp. 20–21 and 78–83; not a daily price feed.
- 17CFTC COT Index ↗
Oct 27 Tuesday positions, released Oct 30 Friday; direct gas and electricity reports read.
- 18CFTC Public Reporting Environment ↗
Page renders without readable tabular content; direct CFTC static reports used instead.
- 19EIA Natural Gas Storage ↗
Oct 29 release for Oct 23 week; official regional numerical table read.
- 20ERCOT-derived 7-day load / peaks ↗
Nov 1 06:30 CST forecast vintage for Nov 2–7; Nov 1 23:30 CDT prior vintage; mirror read.
- 21North Hub 5-minute LMP history ↗
Oct 31 complete day; secondary 5-minute LMP means read; not ERCOT 15-min SPP.
- 22Houston Hub 5-minute LMP history ↗
Oct 31 complete day; secondary 5-minute LMP means read.
- 23West Hub 5-minute LMP history ↗
Oct 31 complete day; fresh search result read; direct page cache may show older Oct 28.
- 26Texas November 1 weather outlook ↗
Nov 1 report: Houston low-80s Sunday/Monday; Tuesday front/rain; context, not a numerical ERCOT load forecast.
- 27ERCOT large-load RFI ↗
Aug–Sep RFI, Oct 12 submission deadline, Dec 10 report target; background, not new release.
- 28ERCOT Batch Zero large-load rule ↗
Jun 18 announcement; 75-MW threshold and 438 GW requests; background.
- 29Vistra linked full report PDF ↗
PDF says week ending Oct 9; table p.1 with Cal27/29 prices and Oct 1 load-zone prices.
- 30NextEra Oct 28 Energy Pulse PDF ↗
PDF p.1: ERCOT Cal26 $39.33/MWh (−$2.43 vs Oct14), gas Cal26 $2.99/MMBtu (−$0.26).
- 31NextEra Oct 14 Energy Pulse PDF ↗
PDF p.1: ERCOT Cal26 $41.76/MWh, gas Cal26 $3.25/MMBtu.
- 32Calpine Oct 29 PDF ↗
PDF p.1: 80 Bcf injection, 3,724 Bcf storage; regional notes Oct22–28.
- 33RWE 2026 Factbook PDF ↗
Aug 2026 Factbook pp. 20–21: 15-project ~5GW flexible gas pipeline; pp. 78–83 battery economics.
- 34CFTC disaggregated natural gas positions ↗
Oct 27 report, NYMEX natural gas contract #023651: managed money long/short 198,900/405,217.
- 35CFTC disaggregated electricity positions ↗
Oct 27 report, ERCOT North RT peak ICE contract #06439R: managed money long/short 63,277/5,245.
- 36Constrained path analysis, historical ↗
Oct 22 BLESSING 1382 $1,104/MWh shadow price and Oct 20 CONCHO HARI1 A $2,503/MWh; old examples, not Nov 1 constraints.
- 37Power to Choose, the PUCT's plan-comparison website ↗
Today's six-TDU plan list was not pulled for this report.
Methodology: day-ahead 25-hour arithmetic averages include repeated HE2*; Oct 31 realized daily averages are 5-minute LMP mirror values, not 15-minute SPP; 08:00 ERCOT SPP was posted at 08:02; EIA storage is weekly; CFTC positions are as of Tuesday Oct 27; supplier forward curves are dated indications. Any 7-day/30-day comparison without a verified comparable series is omitted. This report is market research, not investment advice or a supplier quote.