What Drives Electricity Pricing in ERCOT?
It's not the economy. It's not inflation. It's not what's happening in Washington. In Texas, commercial electricity pricing is a downstream reflection of one thing above all else: natural gas markets. Everything else flows from there.
The Fundamental Relationship
Natural gas fuels roughly 50% of Texas power generation. When gas prices rise, electricity prices follow. When gas prices fall, electricity prices follow — eventually. The two move in approximately 85–90% correlation in the ERCOT market. This matters for commercial buyers because it means the strategic question is never "where is the economy headed?" It's always: where is natural gas supply vs. demand headed, and what weather or geopolitical risks are unpriced in the forward curve? A softening economy is not a reason to wait on locking a contract. A mild weather forecast, a strong storage build, or a surge in renewable generation are. Here's what actually moves the needle.
Forces That Push Prices Down
Oversupply and domestic production
The U.S. shale boom — centered on the Permian Basin, Eagle Ford, and Haynesville formations — unlocked gas volumes the market hadn't priced in. More supply chasing the same demand pushes prices down. This dynamic is the single biggest driver of the extended rate decline from 2008 through 2016, during which Texas commercial electricity rates fell from over 10¢/kWh to around 8¢ — even as the Texas and U.S. economies grew every single year. The lesson: supply fundamentals, not economic cycles, drive electricity prices.
Renewable displacement
Every megawatt-hour generated by wind or solar is a megawatt-hour that doesn't require gas combustion. As Texas wind and solar capacity has expanded dramatically, gas generators run fewer hours — particularly during off-peak periods. Wind and solar provided nearly 40% of ERCOT generation in 2025, directly suppressing gas burn and wholesale clearing prices during daylight and high-wind hours.
Supply disruptions
Freeze-offs — wellhead freeze-ups during hard winters — choke gas production exactly when demand is highest. This double-hit of surging demand and collapsing supply drove the extremes seen during Winter Storm Uri in February 2021. Pipeline outages and Gulf Coast hurricane damage can similarly cut production and transmission simultaneously, as happened during Hurricanes Katrina and Rita in 2005 and Hurricane Ike in 2008.
Extreme weather demand spikes
A brutal Texas summer or a hard freeze simultaneously cranks up electricity demand and can cut gas supply — the combination that makes ERCOT price spikes so severe. When gas peaker plants are the marginal unit keeping the lights on — wind calm, solar generation done for the day — they set the clearing price for the entire grid. ERCOT's current real-time price cap is $5,000/MWh, reduced from $9,000 following the Uri experience.
Mild weather and low demand
Mild summers and winters reduce heating and cooling load. Gas isn't burned as aggressively, storage inventories build, and forward prices soften. 2024 is the clearest recent example — an unusually mild summer kept ERCOT wholesale prices at multi-year lows despite record installed capacity across the grid.
High storage inventories
When EIA weekly storage reports show above-normal injections, traders price in the supply cushion and forward prices soften. Storage levels heading into summer or winter are among the most closely watched short-term indicators for contract timing. A build that consistently exceeds analyst expectations puts downward pressure on the forward curve. A draw that misses expectations puts upward pressure.
Forces That Push Prices Up
LNG Export Competition
U.S. LNG export terminals now compete directly with domestic buyers for the same gas supply. This is a structural change that did not exist before 2016. The Russia/Ukraine shock in 2022 sent European buyers scrambling for U.S. LNG, pulling Henry Hub prices to $8–9/MMBtu — the highest since 2008. This permanent export infrastructure means the extended low-price era of 2014–2020 is unlikely to repeat. There is now a structural floor under U.S. natural gas prices that simply wasn't there before.
Tight storage and capacity constraints
Below-normal storage heading into peak seasons leaves traders with less buffer. Prices run hard on any demand surprise. Compounding this: new gas turbine capacity is supply-constrained through approximately 2030 due to manufacturing backlogs, meaning ERCOT has limited ability to add peaking capacity even as load grows rapidly from data centers, crypto mining, and industrial expansion.
What This Means for Contract Timing
Most commercial buyers think about energy procurement the way they think about other vendor contracts — get three bids, pick the lowest, move on. That approach ignores the one variable that matters most: when you lock.
The same contract signed in February 2016 versus February 2022 at the same load profile would have differed by several cents per kilowatt-hour — a difference of tens or hundreds of thousands of dollars annually depending on usage. The supplier was the same. The market was not.
In ERCOT, there are two seasonal windows of historically lower volatility where conditions tend to favor buyers: late September through mid-November, and mid-February through mid-March. Outside those windows, the odds of catching a meaningful dip in forward pricing are considerably lower.
Monitoring the market — watching the EIA weekly storage reports, following the Henry Hub forward curve, tracking near-term weather forecasts — is the work that separates a well-timed contract from one that just felt like a good deal at the time. And market momentum is what can separate all the regular from those rare, great days to lock.
That's the work we do.
