Texas commercial electricity buyers signing 2027 or 2028 fixed rate contracts this quarter are pricing into a very specific piece of federal analysis. On March 12, 2026, the U.S. Energy Information Administration published Today in Energy ID 67344, comparing its February 2026 baseline Short-Term Energy Outlook against a high data-center demand scenario. In that scenario, ERCOT's 2027 North Hub wholesale price landed at roughly $84.80 per MWh, about $37 per MWh, or 79 percent, above the baseline $47.39 per MWh. EIA's July 7, 2026 STEO and its follow-on coverage in Utility Dive kept the trajectory intact. This is not a residential story. This is the risk premium being embedded into the fixed rates that Texas businesses are quoted right now.

What Happened

The primary source is EIA's March 12, 2026 Today in Energy analysis, "Fossil generation could rise with faster-than-expected growth in data center power demand". EIA modeled two paths: a baseline where ERCOT load grows at roughly 10 percent per year from 2025 through 2027, and a high-demand scenario where load grows at 15 percent per year on stronger data-center build-out. In the high-demand path, ERCOT's 2027 wholesale price was the largest mover of any region EIA studied, averaging 79 percent above baseline.

Two things happened after that publication that matter for a commercial buyer sitting with a 2027 quote. First, EIA's July 7, 2026 STEO reaffirmed record electricity demand for 2026 and 2027, with ERCOT and PJM the load-growth leaders, per Reuters. Second, ERCOT's own June 18, 2026 large-user interconnection snapshot reported more than 438,000 MW of proposed large-user demand, with roughly 90 percent from data centers. Independent trackers refreshed in July 2026 showed the queue closer to 466 GW, still around 90 percent data centers. These are requests, not confirmed operating load, but the direction is a queue that keeps growing, not shrinking. The scenario EIA modeled is the scenario the interconnection pipeline is describing.

Impact on Commercial Electricity Buyers in Texas

The March 12 EIA figure is a wholesale scenario, not a retail contract price. It still reaches every commercial buyer through three specific channels.

Fixed-rate risk premiums widen for 2027 and 2028 exposure. REPs and brokers hedge their book against the forward wholesale curve. When the modeled 2027 outcome sits 79 percent above baseline and the interconnection queue keeps validating the demand story, the risk premium baked into 24-month and 36-month fixed quotes widens. It rarely shows up as a headline warning. It shows up as a bigger spread between 12-month and 36-month rates on the same offer sheet, or as a step-up in the tail-year pricing of a blend-and-extend proposal.

Contract expiration windows in 2027 become the concentration risk. A commercial contract expiring in Q2 or Q3 2027 hits renewal exactly when EIA's scenario predicts peak stress. Any buyer with meaningful load rolling in that window is currently the customer with the least negotiating leverage. The reverse is also true. A contract renewing this fall or winter with a term through mid-2027 covers the buyer through the modeled stress period at today's premium, not tomorrow's.

Locational exposure sharpens on the Oncor and CenterPoint sides of the grid. The June 18 ERCOT queue is not evenly distributed. Large-load projects cluster in the North (Oncor) and Coastal (CenterPoint) zones where the fiber, water, and transmission access data centers require already exists. A commercial account in those TDU footprints faces more concentrated local congestion risk in 2027 than a comparable account in the AEP or TNMP footprints. That translates into a wider ancillary-services and congestion-cost tail in tighter-term index or block-and-index deals.

The 2027 Exposure Test: A Three-Question Framework Before You Sign

Every 2027 or 2028 quote hitting a commercial desk right now deserves the same three-question test. We call it the 2027 Exposure Test, and it takes about 20 minutes with a copy of the offer and the last 12 months of usage.

The 2027 Exposure Test

What share of my contracted term sits inside the 2027 to 2028 EIA stress window? A 24-month contract signed in September 2026 puts roughly 12 to 15 months of usage inside that window. A 36-month contract puts closer to 18 to 24 months there. That share is the load that the modeled 79 percent premium is being priced against.
What is the price gap between my 12-month, 24-month, and 36-month options on this quote? When the gap is unusually wide, the REP is telling you where they see 2027 risk. A flat gap means the desk is comfortable with the tail. A steep gap means the desk is not, and you are being asked to absorb their uncertainty.
What is my monthly bill tolerance for a wholesale spike passed through? Index and hybrid products transfer more of the wholesale outcome to the buyer. If the finance team cannot tolerate a 20 to 40 percent monthly swing during a July or August 2027 heat event, index exposure inside the stress window is the wrong instrument, regardless of the headline rate.

What You Should Do

Map every commercial meter you operate against its contract expiration date. Flag anything expiring between January 2027 and December 2028 as concentrated exposure to the EIA stress window.
Pull the last 12 months of interval or monthly usage for each flagged meter. Note the summer peak share, because that is the tonnage that gets repriced against 2027 congestion risk.
Ask any REP or broker quoting your renewal to break out the price component of each term year. A 36-month quote is really three annual prices blended into one. The tail years, 2028 and 2029 on a contract signed today, carry the widest scenario risk.
If you have flexibility, consider covering the 2027 stress window with a term that starts now rather than mid-2027. Locking in today against a modeled scenario is a defensible trade even if the scenario softens.
Compare offers against the current Texas commercial market benchmarks on our Texas commercial electricity rates page, so a widening risk premium becomes visible instead of buried inside a headline rate.

Questions to Ask Your REP or Broker

How much of the price on my 2027 and 2028 tail years is data-center-driven load growth versus fuel-cost assumption?
What forward curve did you use to price the 24-month and 36-month options on this quote, and when was it pulled?
If ERCOT's queue continues to add data-center load through the end of 2026, how does that reprice the offer you are showing me today?
What is the pass-through clause for TDU-level congestion charges in 2027, and does the quote include a cap?
Would you show me the same product structure with a start date of October 2026 instead of a January 2027 start, so I can compare covering the stress window head-on?
What does your book look like for accounts my size and TDU in 2027, and does that concentration influence the premium you are quoting me?

Frequently Asked Questions

Is the 79 percent figure a certainty or a scenario?

It is a scenario, not a forecast. EIA compared its baseline February 2026 STEO against a high data-center demand scenario. In the high-demand case, the 2027 ERCOT North Hub price averaged $37 per MWh (79 percent) above baseline. It is one modeled outcome, but it is the outcome the ERCOT queue data, 438 GW to 466 GW of proposed large-user load as of June and July 2026 and roughly 90 percent data centers, keeps pushing toward, not away from.

Why is ERCOT hit harder than PJM or MISO in the modeling?

ERCOT is an isolated grid with very limited ability to import power from neighboring regions. When demand spikes, ERCOT cannot lean on interconnected supply the way PJM or MISO can, so the same incremental load translates more directly into wholesale price movement. EIA's write-up flags this explicitly as the reason ERCOT showed the largest price delta in the high-demand scenario.

How does a wholesale price scenario reach my commercial fixed rate?

REPs and brokers hedge the wholesale exposure inside every fixed rate they quote. When the forward curve for 2027 and 2028 moves up, or when supply-side uncertainty widens, the risk premium baked into a 24-month or 36-month fixed offer widens with it. You do not see the hedge. You see a higher all-in rate per kWh, sometimes with a wider spread between term lengths on the same quote sheet.

Does this mean we should just sign short and wait?

Not automatically. Short terms leave you exposed to any 2027 spike EIA modeled. Long terms lock in today's premium against a scenario that might not materialize. The useful move is a structured decision: quantify the premium each term carries versus a documented range of 2027 outcomes, and match term length to the load's tolerance for month-to-month volatility, not to a bet on which scenario wins. For the current aggregate benchmarks, see our Texas commercial electricity market data.