On Tuesday, November 3, the West Texas hub in ERCOT’s day-ahead market cleared at -$1.19/MWh at hour ending 11 and at $183.08/MWh at hour ending 23 — a $184.27 swing in the same zone, on the same day, in the same market. At midday, West Texas power was effectively free. Twelve hours later, it was the most expensive power in the state.
The same pattern repeated all week. The previous morning, Wednesday, November 4, the West hub opened the day at $120.76/MWh, $43 above Houston. On Thursday, November 5, the West Texas hub cleared -$1.11/MWh at hour ending 15 while Houston cleared $43.00 in the same hour — a $44 gap between two Texas hubs. And in the November 10 day-ahead market it peaked at $86.44 at hour ending 18, $34.36 above Houston. On November 3, the West load zone — the price at which West Texas load actually settles — cleared $201.92 at hour ending 23, higher even than the hub. Nor was it confined to day-ahead: on Monday, November 2, Houston real-time prices hit $276.19/MWh at 4:15 p.m. while West Texas sat near $1.
The premium has a name, and it is not a power plant, a fuel price, or a weather event. It is SCRCV-KNAPP, a 138kV transmission line in the Stanton corridor. It bound in every day-ahead market checked from November 2 through November 9. On November 4 it posted a shadow price of $1,030/MWh at hour ending 1. A second West Texas line, the 69kV MRVLY-ESTLD, cleared $1,282/MWh that same morning. By November 10, the heaviest congestion had moved to two small 69kV lines near San Angelo — LAKENASW-SAMATHIS and BIGLAKE-PHBL_TAP, each rated at just 38 MW — with shadow prices up to $1,627/MWh at hour ending 5.
Three prices, three different things
Before going further, it is worth getting the quantities straight — the numbers in this story are routinely confused with each other. A hub price, a shadow price, and a nodal price are three different measurements, and the $1,627 figure is not a price anyone paid for electricity.
A hub price is the price of energy at a defined basket of nodes, averaged into a single reference number. HB_WEST is the West Texas hub — the benchmark contracts settle against, and the number that swung $184 on November 3. A nodal price is the price at a single physical point on the grid, and it can be far more volatile than any hub — a constraint binding next to a node can send its price far above or below its neighbors. A load zone price is a load-weighted average of the nodes inside a zone, and it is where most load actually settles — which is why the West zone’s $201.92 at hour ending 23 on November 3 was higher than the hub’s $183.08 in the same hour.
A shadow price is different again. It is the value the market would save per megawatt-hour if one constrained line could carry one more megawatt — a diagnostic, not a settlement price. When SCRCV-KNAPP posted $1,030/MWh on November 4, that meant the market was willing to pay $1,030 for one additional megawatt of capacity on that line in that hour. The shadow price is the wire pricing itself. And the fact that the highest shadow prices in the November 10 market came from lines rated at 38 MW is itself the point: in West Texas, the binding constraint is now small enough to fit on a single rural feeder.
Noon: the solar trap
The midday side follows directly from the negative-price mechanics in our earlier explainer on why power prices spike. West Texas now holds an enormous concentration of utility-scale solar, and at midday that solar produces more power than the local grid can use or move east. When the export path binds, the surplus has nowhere to go, and the local price falls to zero or below.
Negative prices are not a glitch. Solar generators with production tax credits earn a per-megawatt-hour payment, so they can rationally bid below zero and still come out ahead. Thermal plants face shutdown and restart costs that make it cheaper to pay to stay online than to cycle off and back on. So the price goes negative, and the signal it sends is precise: at that hour, in that place, one more megawatt of solar has negative value.
What makes West Texas distinctive is not that this happens — negative midday prices are routine in solar-heavy regions — but that the same zone flips to a large premium within hours. That is the part that deserves attention, because it tells you the constraint is not a one-directional export problem. It is a corridor that binds both ways.
Midnight: the import wall
The overnight premium is the mirror image, and it is driven by load, not by generation. The Permian Basin’s electricity demand has been growing far faster than the rest of Texas. ERCOT’s independent market monitor reported that West zone average load rose 12.3 percent in 2025, against 6.1 percent system-wide, driven by oil and gas electrification and large new loads. ERCOT warned its board in February 2026 that Far West load was outgrowing planned transmission upgrades, with a risk of local load shedding on low-wind nights.
That is the setting for the overnight hours. When the sun is down, West Texas load — oilfield operations, crypto mining, data centers, battery charging — still needs power the local fleet cannot always cover. Power has to flow in from the east, over the same corridor that carries solar out at midday. When that import path binds, West Texas becomes an island, and its price rises to whatever the most expensive local resource costs to run. The $183.08 print at hour ending 23 on November 3, and the $201.92 West zone price in the same hour, are what an import-constrained load pocket looks like.
Wind complicates the picture rather than simplifying it. West Texas wind is typically strongest overnight, and on a windy night it can cover much of local demand. But wind is variable, and when it dips, imports have to rise to fill the gap — over the same lines, in the same hours. The corridor’s flow direction is not published hour by hour in the market data available for this piece, so the precise split between export-side and import-side binding overnight is not established in the sources checked. What is established is the outcome: the line bound, and the West price carried a large premium. The November 5 analysis flagged the chronic-versus-outage question as unresolved; the November 10 follow-up argued that six binding days on one line, followed by congestion migrating to nearby lines, reads as a West Texas condition rather than a single outage. That is a reasonable inference, not a confirmed cause.
A wires story, not a scarcity story
Here is the test that separates this event from the price spikes in our earlier explainer: in a genuine scarcity event, the system itself is tight — reserves thin, the operating reserve demand curve adds its adder, and prices rise across the whole footprint. The October 13 event in PJM was that kind of event — a maintenance-season squeeze that pushed the Western Hub past $1,500/MWh on a mild day because tens of gigawatts of capacity were offline.
Nothing like that was happening in Texas on November 3. System load was unremarkable for early November. Houston cleared $43 at the same hour West Texas cleared -$1.11 on November 5. On November 2, Houston real-time prices spiked to $276.19 while West Texas sat near $1 — the two hubs moving in opposite directions on the same afternoon. A system-wide scarcity event cannot produce that pattern. Only a binding wire can: one side of the constraint priced by surplus, the other by shortage, with the line itself setting the spread. There was no shortage of electricity in Texas on November 3 — only a shortage of wire in the Stanton corridor, priced in both directions within twelve hours.
South Texas had its own line
West Texas was not the only congestion story that week. A constraint at the Bruni substation in Webb County, east of Laredo, posted a shadow price of $394.97/MWh at hour ending 2 on November 3. On November 5, HB_SOUTH cleared $60.76/MWh at hour ending 17 while HB_NORTH cleared $15.29 — a $45.47 gap. HB_SOUTH peaked an hour later at $64.47.
The South Texas numbers carry a useful cross-check. With Henry Hub natural gas at $2.63 per MMBtu, per EIA data, a $64.47 power price implies a heat rate of 24.5 MMBtu per megawatt-hour. An efficient gas plant runs at 7 to 8. The gap between those two numbers is not fuel cost. It is congestion, priced into the hub.
What it means for buyers
The $184 swing is not an abstraction. It lands directly in settlement, and which side of it you paid depends on what you signed. ERCOT is an energy-only market: there is no capacity charge, no separate payment that smooths these hours out. Congestion prices straight into settlement every 15 minutes in real time, and the day-ahead market that produced these numbers is financially binding. There is no capacity market to absorb the shock, as there is in PJM or ISO-NE. The wire is the market.
A business buying power in the West zone on an index agreement pays the evening and overnight premium — the hours when the zone runs $25 to $43 above Houston are the hours a Midland or Odessa facility is buying. For a buyer of West Texas solar through a virtual power purchase agreement, the exposure runs the other way. A virtual PPA typically settles at HB_WEST: the project earns the West hub price in the hours it produces, and the buyer carries the difference between that price and the price where its own load settles. Solar produces at midday — the same hours West Texas cleared near or below zero. On November 5, that gap was $44/MWh in a single hour. Over a year of midday hours, it compounds into real money, and it is the reason the phrase “basis risk” exists: a hedge settled at the wrong location can be perfectly sized in volume and still lose money.
Two questions belong in any West Texas agreement discussion now. First, does the offer settle at HB_WEST, at your own load zone, or at your own node? Those three prices diverged by tens of dollars in the same hour last week. Second, does the project or the buyer hold any transmission hedge — congestion revenue rights, the financial instruments ERCOT auctions that pay the holder the price difference between two settlement points? CRRs are funded by the congestion rents the operator collects. They are not free, they are not physical, and they settle on day-ahead prices, so they do not cover real-time deviations. But they are the difference between carrying the spread and paying someone else to carry it.
The fix is steel, and it is slow
None of this is a surprise to the people who plan the Texas grid. The Permian Basin reliability plan, required by House Bill 5066 in 2023 and approved by the Public Utility Commission of Texas in October 2024, is the long-term answer: ERCOT’s first extra-high-voltage 765kV lines, approved by the commission in April 2025, with the first phase targeting a 2030 in-service date. ERCOT’s Delaware Basin stages add capacity in steps — Stage 2 energized in June 2026, Stage 3 expected in December 2026, Stage 4 in December 2027, Stage 5 not until December 2029. The monitor’s numbers explain the urgency: day-ahead congestion rose 26 percent in 2025 and real-time congestion 32 percent, and the West Zone posted ERCOT’s highest annual zonal energy prices for a second straight year. ERCOT endorsed more than $14 billion in transmission projects by the end of 2025.
But the November 10 market carries a warning about what happens while the steel is being built. The heaviest congestion that day was not on SCRCV-KNAPP. It had moved to two 69kV lines rated at 38 MW each, with shadow prices up to $1,627/MWh. Relieve one bottleneck and the next-smallest wire becomes the constraint. That is the character of a system where load growth is outrunning transmission by years, and where the permanent fix is a 765kV backbone that will not be energized until the end of the decade. In the meantime, the price signal will keep finding the weakest wire in the corridor.
The $184 swing is the market telling the truth about a wire. West Texas generates more solar at midday than its grid can move, and it consumes more power at night than its grid can import. One 138kV line sits between those two facts, and for one week in November it bound every single day. Whether it keeps binding into the winter, and what the next congestion revenue rights auctions charge for West Texas basis, will tell you whether this week was a preview or a peak. Until the steel arrives, the price will keep saying so: in both directions, sometimes on the same day.