How Wholesale Electricity Markets Work: PJM and ISO New England

Your electricity supplier doesn't generate power. They buy it—from wholesale markets you've probably never heard of—and resell it to you with a markup.

Understanding these markets won't make you an energy trader, but it will explain why your rates change and when to lock them in. PJM runs the market for Ohio and Pennsylvania (65 million customers). ISO New England handles Massachusetts. ERCOT covers Texas as its own isolated grid.

What matters: Wholesale prices move constantly based on natural gas costs, weather, and how many power plants are running. When you sign a fixed-rate contract, your supplier is betting on what those prices will do. When you go variable, you're making that bet yourself. Either way, wholesale markets set the floor for what you pay.

Energy markets clear every hour, setting prices for actual electricity delivery.

Day-ahead market: The day before electricity flows, generators and suppliers submit bids and offers. PJM and ISO-NE run optimization algorithms that clear the market—matching supply to projected demand and setting hourly prices. About 95% of electricity trades day-ahead.

Real-time market: Because actual demand differs from projections, real-time markets balance the grid minute-by-minute. Prices can spike dramatically during unexpected events—a generator tripping offline, extreme weather, or transmission constraints. Real-time prices averaged $35-50/MWh in 2025 but spiked above $1,000/MWh during winter storms.

How this affects you: Your retail supplier buys in these markets. Fixed-rate plans hedge against volatility—you pay the same regardless of wholesale swings. Variable-rate plans pass through some or all wholesale price movements, for better or worse.

Capacity markets pay power plants to be available during peak demand—separate from actual electricity generation.

Why capacity matters: The grid needs enough generation capacity to meet peak demand plus a reserve margin. Without capacity payments, some plants might retire even though they're needed for reliability during extreme conditions.

The auction process: PJM runs capacity auctions three years in advance. Generators bid to provide capacity; the auction clears at a price that secures enough supply. The 2025-2026 PJM capacity auction cleared at $269.92/MW-day—an 833% increase from $28.92 the previous year.

Cost allocation: Capacity costs flow to retail customers through suppliers. That 833% increase translates to roughly $8-12/month more for typical households starting June 2025. Commercial customers with higher peak demand face proportionally larger increases.

ISO New England's FCM: The Forward Capacity Market works similarly, though pricing and rules differ. Massachusetts customers saw capacity costs around $3.58/kW-month in recent auctions.

Wholesale electricity uses locational marginal pricing (LMP)—the cost of serving the next increment of demand at a specific location.

Marginal cost pricing: Markets clear based on the marginal (last) unit needed to meet demand. If demand is low, cheap baseload plants (nuclear, efficient combined cycle) set the price. As demand rises, more expensive peaking plants set the price. Everyone gets paid the marginal price—even the cheap plants.

Natural gas's outsized influence: Gas-fired plants often set marginal prices because they're frequently the last units dispatched. When natural gas prices rise, wholesale electricity prices follow—even though much generation comes from cheaper sources. This dynamic explains why gas prices correlate so strongly with electricity rates.

Location matters: Transmission constraints create price differences across the grid. Congested areas pay more because power can't flow freely from cheaper distant sources. Major cities often have higher LMPs than rural generation hubs.

PJM Interconnection operates the largest wholesale electricity market in North America, serving 65 million people across 13 states plus Washington DC.

Generation mix: PJM's power comes from nuclear (32%), natural gas (43%), coal (15%), wind (4%), solar (2%), and hydro (1%). The nuclear fleet provides stable baseload; gas plants handle intermediate and peak loads.

Recent market trends: The 2025-2026 capacity auction's 833% price increase signals significant market stress. Contributing factors include accelerating coal and nuclear retirements, explosive data center demand growth, and insufficient new generation construction.

What this means for Ohio and Pennsylvania: Both states draw from PJM's market. Capacity cost increases affect everyone—whether you're on utility default or competitive supply. Suppliers must pay higher capacity charges and pass them through. Shopping for competitive supply can't avoid capacity costs; it can only optimize the energy component.

ISO New England manages the wholesale market for six New England states, including Massachusetts.

Unique challenges: New England faces distinct reliability challenges. Limited natural gas pipeline capacity creates winter price spikes when gas competes for heating demand. Geographic constraints (ocean to the east, limited transmission to the west) create import limitations.

Generation transition: New England is rapidly decarbonizing. Offshore wind projects totaling 5+ GW are in development. However, this transition creates near-term reliability concerns as traditional generators retire before replacements come online.

Price volatility: ISO-NE wholesale prices are among the most volatile in the country. Winter 2025 saw prices spike above $200/MWh during cold snaps. Massachusetts retail rates—already the highest in the continental U.S.—reflect this underlying wholesale volatility.

Capacity market: The Forward Capacity Market secures reliability but adds costs. Recent FCM prices around $3.58/kW-month contribute to Massachusetts's high retail rates.

Understanding wholesale markets helps you make smarter electricity choices.

Fixed vs. variable rates: Fixed-rate plans lock in prices regardless of wholesale fluctuations. You're paying for the supplier to manage volatility risk. Variable rates expose you to wholesale movements—potentially cheaper in stable markets, risky during price spikes.

Timing matters: Wholesale prices follow seasonal patterns. Locking fixed rates during shoulder seasons (spring, fall) often captures lower prices than signing during summer or winter peaks.

Capacity cost visibility: Capacity charges typically appear bundled into your supply rate rather than as separate line items. When capacity prices surge (like PJM's 833% increase), even fixed-rate plans eventually adjust—usually at contract renewal.

Market monitoring: ElectricRates.org tracks wholesale market trends affecting retail rates in Ohio, Pennsylvania, Massachusetts, and Texas. Understanding where markets are heading helps you decide when to lock rates and for how long.