Power Choosers
Electricity Market Navigator 2026
Strategic intelligence for commercial energy decision-makers across ERCOT. Built for CFOs, Ops Directors, and Facilities leaders who need clarity, timing, and action.
The Bottom Line
Locking contracts in Q1–Q2 2026 can protect margins by 15–25%. Waiting until summer peak season risks absorbing higher rates and volatile capacity charges.
Who This Guide Is For
- CFOs managing energy as a strategic cost driver
- Operations & Facilities leaders responsible for uptime and spend
- Commercial real estate and multi-site managers across ERCOT
What You Get
- Market data aligned to ERCOT realities
- Three-lever playbook (fixed, hybrid, demand response)
- Action timeline with the critical Q1–Q2 window
Data centers and industrial growth are accelerating demand, while supply additions trail. The result: compressed reserve margins and a two-tier price reality—stable baseload with extreme peak-hour volatility.
Price Components
| Component | 2025 Baseline | 2026 Forecast | Change |
|---|---|---|---|
| ERCOT-North Wholesale | $35–38/MWh | $48–55/MWh | +26% to +57% |
| Peak-Hour Pricing (Summer) | $65–80/MWh | $100–130/MWh | +54% to +62% |
| Commercial Retail Rates | 17.0 ¢/kWh | 17.6 ¢/kWh | +3.5% |
| Non-Commodity Charges | 4.2 ¢/kWh | 4.5 ¢/kWh | +7.1% |
Fixed-Rate Hedging
Best for budget certainty and operations that cannot flex demand.
- Target 24–72 month terms; pick the term that fits your risk and forward curve.
- Lock 6–24 months before contract expiry—earlier if summer volatility is looming.
- Exploit backwardation (future strips still below spot).
- Protects against peak-hour spikes.
Block & Index (Hybrid)
Best for moderate flexibility and upside capture.
- Fix 60–70% baseload; float 30–40% for dips.
- Continuous monitoring to time index buys.
- Blend achieves protection with optionality.
Demand Response
Best ROI lever for capacity charge reduction.
- Focus on 4CP hours (June–Sept highest peaks).
- 10–20% curtailment can lower annual capacity tags.
- Pair with controls, batteries, or operational shifts.
Decision Inputs
- Risk tolerance (price swings you can absorb)
- Operational flexibility (load shifting potential)
- Contract timing (avoid peak-season starts)
- Regional constraints (transmission, local congestion)
Q1 2026: Audit & Align
- Collect the past 12 months of usage; profile load and peaks.
- Assess risk tolerance; model 15–30% increase scenarios.
- Select procurement mix (e.g., 70/30 fixed/index).
- Draft RFP for 8–12 qualified suppliers.
Q2 2026: Procure & Lock
- Issue RFPs; negotiate price, terms, DR integration.
- Execute agreements before summer heat.
- Enroll demand response; set alerts and playbooks.
Q3 2026: Peak Season
- Respond to ERCOT peak alerts (4CP hours).
- Track curtailment vs. capacity tag targets.
- Review spot vs. contract performance weekly.
Q4 2026: Review & Plan
- Validate savings vs. 2025 baseline.
- Score supplier performance; decide on renewal strategy.
- Plan 2027–2028 procurement with refreshed data.
Baseline load, contract dates, decision-makers, and budget scenarios.
Finalize risk mix (fixed/index/DR), prepare RFP specs, shortlist suppliers.
Issue RFPs, negotiate, execute agreements, enroll DR, set monitoring.
Don't wait for summer volatility.
The decisions you make in the next 90 days will define your cost exposure for 2027–2032. We’ll benchmark your current rate, model fixed vs. index scenarios, and line up suppliers so you can move decisively.
Free Risk Assessment
- Benchmark vs. available market options
- Demand charge & capacity tag analysis
- Fixed vs. index scenarios (2026–2027)
What We Need
- Most recent utility bill (usage + demand)
- Contract renewal dates
- Sites, load profile, flexibility