Peak vs Off-Peak Power: Contracts, LMP, and Trading Strategies
Peak vs off-peak pricing is fundamental to power market trading. Unlike other commodities, electricity cannot be economically stored at scale, so wholesale prices vary dramatically by time of day. Understanding peak vs off-peak distinctions—and how locational marginal pricing affects prices at different nodes—is essential for utilities, traders, and large commercial consumers managing electricity costs and hedging exposure.
This article covers wholesale power trading—the market where generators, utilities, and traders buy and sell electricity in bulk. If you’re looking for information about your home utility’s “time-of-use” rates, those retail programs are based on similar principles but with different hour definitions and pricing structures set by your local utility.
What Are Peak and Off-Peak Power Hours?
Peak hours are periods of highest electricity demand—typically weekday business hours when commercial and industrial loads are running. Off-peak hours cover evenings, nights, weekends, and holidays when demand falls and cheaper baseload generation can meet most load.
Peak hour definitions vary by market and product. There is no single “NERC standard” for peak hours—each ISO/RTO and exchange defines on-peak periods in its tariffs and contract specifications.
Peak Hour Definitions by Market
| Market | On-Peak Hours | Days | Holidays |
|---|---|---|---|
| PJM / Eastern | HE 0800–2300 (7am–11pm) | Monday–Friday | Excludes NERC holidays |
| ERCOT | HE 0700–2200 (6am–10pm) | Monday–Friday | Excludes NERC holidays |
| CAISO / Western | HE 0700–2200 (6am–10pm) | Monday–Saturday | Excludes NERC holidays |
Hour Ending (HE) notation means the hour ending at that time. HE 0800 covers 7:00am to 8:00am. This convention is standard in power markets—misreading it is a common mistake among new traders.
Peak power prices can trade at a significant premium over off-peak prices. The premium varies by season, weather, fuel costs, and renewable penetration. In summer months with high air conditioning load, peak prices may exceed off-peak by $30–$60/MWh or more. But solar penetration has compressed midday peak prices in many markets, and the spread can even invert during shoulder months.
Baseload, Intermediate, and Peaker Plants
Electricity prices reflect the merit order—the dispatch stack from cheapest to most expensive generators. Understanding which plants set prices at different times explains why peak hours cost more.
| Plant Type | Fuel | Marginal Cost | Characteristics |
|---|---|---|---|
| Baseload | Nuclear, hydro, coal | $15–$35/MWh | Run continuously, slow to ramp, lowest cost |
| Renewables | Wind, solar | ~$0/MWh | Zero marginal cost, variable output based on weather |
| Intermediate | CCGTs, some coal | $35–$60/MWh | Flexible, moderate cost, load-following |
| Peakers | Gas turbines, oil-fired | $80–$150/MWh | Fast start, high cost, only run during peak demand |
| Battery Storage | Stored energy | Varies by charge cost | Shifts energy from low to high price hours |
During off-peak hours, the marginal generator is often a low-cost baseload plant or renewable source (especially wind at night). During peak hours, intermediate and peaker plants are more likely to be dispatched, generally pushing prices higher. Battery storage increasingly arbitrages this spread—charging when prices are low and discharging during evening peaks.
Watch for the “duck curve” in markets with high solar penetration. Midday prices collapse when solar floods the grid, then spike during the evening “net peak” as solar drops and demand remains high. This has compressed traditional peak spreads in California and Texas.
On-Peak vs Off-Peak Power Contracts: 5×16, 7×8, and 7×24
Wholesale power contracts are structured around standardized time blocks. The naming convention reflects days per week and hours per day—5×16 means 5 weekdays × 16 peak hours.
| Contract | Hours/Day | Days/Week | Hours/Week | Description |
|---|---|---|---|---|
| 5×16 (Peak) | 16 | 5 (Mon–Fri) | ~80 | On-peak weekday hours only |
| 6×16 (Peak) | 16 | 6 (Mon–Sat) | ~96 | Western markets include Saturday on-peak |
| Off-Peak (composite) | Varies | All days | ~88 | All non-peak hours (weeknight + weekend) |
| 7×8 (Nights) | 8 | 7 (all days) | ~56 | Overnight strip only (e.g., 10pm–6am) |
| 2×16 (Weekend) | 16 | 2 (Sat–Sun) | ~32 | Weekend daytime hours only |
| 7×24 (ATC) | 24 | 7 (all days) | 168 | Around-the-clock, all hours |
The term “16×8” appears in some market jargon, referencing 16 peak hours and 8 off-peak hours per weekday. However, the standard contract shorthand uses the days × hours format above.
A trader buys 50 MW of PJM Western Hub 5×16 peak power for July 2026:
- Peak hours per day: 16
- Peak days in July 2026: 22 (23 calendar weekdays minus 1 NERC holiday)
- Total MWh: 50 MW × 16 hours × 22 days = 17,600 MWh
- At $75/MWh peak price: 17,600 × $75 = $1,320,000
How Locational Marginal Pricing Affects Peak Power Prices
Locational Marginal Price (LMP) is the cost to serve one additional megawatt at a specific point on the grid. In organized wholesale markets like PJM, ERCOT, and CAISO, prices are calculated at thousands of individual nodes.
Where:
- Energy component: The system-wide marginal cost of generation
- Congestion component: Additional cost (or credit) from transmission constraints
- Loss component: Marginal electrical losses on the transmission system
PJM alone has over 10,000 pricing nodes. During congestion, LMPs can differ by $50/MWh or more between nearby locations. This matters for traders: buying power at one node and delivering to another can expose you to basis risk—the difference between source and sink LMPs.
Congestion and Transmission Constraints
Transmission lines have physical limits—thermal ratings, voltage constraints, and stability limits. When power flows approach these limits, the grid operator must redispatch generation, often running more expensive local plants instead of importing cheaper power.
Consider a simplified three-node network with one transmission constraint:
| Scenario | Node 1 (Cheap Gen) | Node 2 (Load) | Node 3 (Expensive Gen) |
|---|---|---|---|
| Unconstrained | $12/MWh | $12/MWh | $12/MWh |
| Line 1–2 constrained | $10/MWh | $14/MWh | $12/MWh |
When unconstrained, all nodes price at the marginal generator’s cost. When the line to the load is constrained, the load node pays more ($14) while the cheap generator’s node drops ($10). The $4/MWh difference is the congestion charge.
Congestion is unpredictable. A single line outage can suddenly create large price differentials between nodes that normally price together. Basis risk can turn a profitable trade into a loss if you haven’t hedged your location exposure.
Financial Transmission Rights and Congestion Revenue Rights
To hedge congestion risk, markets offer financial instruments that pay the holder when LMPs differ between two points:
- FTRs (Financial Transmission Rights): Used in PJM, MISO, ISO-NE
- CRRs (Congestion Revenue Rights): Used in CAISO, ERCOT
Despite different names, the economic function is similar: hedge the congestion component of LMP differences.
A utility buys power at PJM Western Hub but delivers to a constrained load zone. It purchases a 50 MW FTR for one month (720 hours):
- Source congestion component: $2/MWh average
- Sink congestion component: $17/MWh average
- FTR payoff: ($17 − $2) × 50 MW × 720 hours = $540,000
The FTR payment offsets the congestion cost of delivering to the constrained zone. Note: FTRs settle on the congestion component of day-ahead LMPs, not the full nodal price.
FTRs and CRRs are not perfect hedges. They settle against day-ahead congestion, which may differ from real-time prices. They also face revenue adequacy risk—if total congestion revenue is insufficient, FTR payouts may be prorated. Obligations can have negative value if congestion reverses (you pay instead of receive).
Trading Strategies Around Peak/Off-Peak
Power traders use several approaches to profit from peak vs off-peak price dynamics:
Peak Spread Trading
Go long peak / short off-peak when expecting demand spikes (heat waves, cold snaps). The strategy profits when the peak-to-off-peak spread widens.
Heat Rate Trades
Combine natural gas and power positions to trade implied generation economics. A spark spread combines short gas and long power—profitable when power prices exceed gas-fired generation costs.
Congestion Trades
Use FTRs/CRRs or basis swaps to profit from anticipated transmission constraints. Requires deep knowledge of grid topology and outage schedules.
Seasonal Strategies
Trade summer vs winter peak contracts. Air conditioning load drives summer peaks; heating load affects winter peaks (especially in gas-dependent regions). Shoulder months (spring/fall) typically see compressed spreads.
Monitor weather forecasts, planned generation outages, and transmission maintenance schedules. These fundamentals drive short-term peak/off-peak spreads more than any technical indicator.
Peak Block vs Off-Peak Block vs Around-the-Clock
Choosing the right contract structure depends on your load profile and risk tolerance:
Peak Block (5×16 / 6×16)
- Hours: 80–96 per week (weekday/Saturday peaks)
- Price: Highest per MWh
- Volatility: Highest—sensitive to demand, outages, weather
- Best for: Commercial/industrial loads concentrated in business hours
Off-Peak Block
- Hours: ~88 per week (weeknight + all weekend hours)
- Price: Lowest per MWh
- Volatility: Lower—often set by baseload or renewables
- Best for: Night-shift manufacturing, overnight processes
Around-the-Clock (7×24)
- Hours: 168 per week (all hours)
- Price: Blended average of peak and off-peak
- Volatility: Moderate—diversified across all hours
- Best for: Baseload hedging, data centers, continuous process industries
Common Mistakes in Peak/Off-Peak Valuation
- Assuming peak hours are identical across ISOs — PJM, ERCOT, and CAISO each define on-peak differently. Always check the specific market’s tariff.
- Ignoring NERC holiday schedules — NERC holidays are treated as off-peak in most markets, even if they fall on a weekday.
- Confusing MW and MWh — MW is capacity (power); MWh is energy delivered. A 50 MW peak block delivers 17,600 MWh in a 22-weekday month, not 50 MWh.
- Misreading hour-ending notation — HE 0800 covers 7am–8am, not 8am–9am.
- Using day-ahead prices for real-time exposure — Day-ahead and real-time markets can diverge significantly. Imbalance charges apply to deviations.
- Applying retail TOU hours to wholesale contracts — Your utility’s time-of-use rate schedule is different from ISO peak definitions.
- Treating FTRs as perfect hedges — Revenue adequacy, basis differences, and auction-price risk mean FTRs rarely provide a 100% hedge.
Limitations of Standard Peak Hour Definitions
Standard peak hour definitions may not match actual high-price hours. The grid has evolved, but many contract definitions haven’t kept pace.
Summer heat waves: Actual price spikes often occur from 4pm–8pm as temperatures peak and solar output declines, not uniformly across the 16-hour peak window.
Solar penetration: Behind-the-meter solar collapses midday prices (the “duck curve”), creating an evening “super-peak” from 5pm–9pm when solar drops but demand remains high. Standard peak definitions average expensive evening hours with cheap midday hours.
ERCOT scarcity events: Operating reserve demand curves can push prices up to the $5,000/MWh cap at any hour—scarcity events don’t respect standard peak boundaries.
Regulatory evolution: Some ISOs are reconsidering peak definitions. CAISO and other markets have proposed or piloted “super-peak” products covering evening ramp hours. Peak premium can collapse when solar penetration is high, fundamentally changing the economics of peak contracts.
Frequently Asked Questions
Disclaimer
This article is for educational purposes only and does not constitute investment or trading advice. Peak hour definitions, contract specifications, and market structures change over time—always verify current tariffs and contract terms with the relevant ISO/RTO or exchange. Past price relationships do not guarantee future performance.
