Electricity feels simple from the consumer’s perspective. You flip a switch, and the lights turn on. When prices rise, it is easy to assume that a specific power plant decided to charge more, or that electricity comes directly from a particular generator down the road. In reality, as a researcher, former quantitative analyst in electricity markets, and Eclipse founder, Neel Somani explains, the U.S. power market is a highly coordinated, continuously optimized system that blends physics, economics, and engineering constraints.
Understanding how it works requires stepping away from the idea that electricity is delivered in a straight line from one producer to one consumer. Instead, electricity flows across a synchronized network, and prices are determined by a structured market process designed to keep supply and demand in balance every second.
Electricity Does Not “Come From” a Single Generator
One of the most common misconceptions about electricity is that it travels directly from a specific generator to your home or business. Neel Somani shares that this is not how the grid operates. In alternating current (AC) systems like those in the United States, electricity must be generated at a precise frequency, 60 Hz. Generators across a region must rotate in sync to maintain that frequency. Power flows across the network according to physical laws, not contractual arrangements. Once electricity enters the grid, it becomes part of a shared pool.
When you consume power, you are not drawing from a particular power plant. Instead, you are participating in a region-wide balancing act where total generation must match total demand at every moment. Because electricity cannot easily be stored at scale, the system must constantly adjust generation to meet real-time consumption. That balancing function is at the heart of how power markets are structured.
The Role of ISOs and RTOs
In most of the United States, wholesale electricity markets are managed by centralized entities known as Independent System Operators (ISOs) or Regional Transmission Organizations (RTOs). Examples include PJM in the Mid-Atlantic, CAISO in California, ERCOT in Texas, and MISO in the Midwest.
These organizations do not own power plants. Instead, Neel Somani explains that they coordinate the market and operate the transmission grid. Their primary responsibilities include:
ISOs and RTOs act as neutral coordinators. They collect bids from generators, forecast demand, account for transmission constraints, and solve a large optimization problem to determine the most economically efficient dispatch of generation resources.
How Generators Submit Bids
Power suppliers, including natural gas plants, coal plants, nuclear facilities, wind farms, and solar installations, submit bids into the market. A bid typically specifies how much electricity the generator is willing to produce and at what price.
Neel Somani reveals that these bids are submitted to two primary markets:
Each generator has different operating characteristics and costs. A nuclear plant may have low marginal fuel costs but limited flexibility. A natural gas peaker plant may be expensive, but it can ramp quickly. Wind and solar may have near-zero marginal cost but are dependent on weather conditions. The ISO or RTO collects all these offers and stacks them from lowest to highest cost. Neel Somani understands that this process is known as economic dispatch.
Why the Cheapest Power Goes First
In principle, the system dispatches the lowest-cost generators first. If demand for a given hour is 1,000 megawatts (MW), the ISO selects the combination of bids that can supply those 1,000 MW at the lowest total cost, subject to operational constraints.
However, this “cheapest first” rule has caveats. Transmission limits, ramping constraints, reliability requirements, and reserve margins all influence dispatch decisions. Electricity cannot be moved infinitely across regions; congestion in transmission lines may require running a more expensive local generator even when cheaper power is available elsewhere. Still, at a high level, the dispatch process resembles stacking supply offers from lowest to highest cost until demand is met.
Why the Marginal Unit Sets the Price
Here is where most misunderstandings arise. Suppose demand is 1,000 MW. The first 900 MW might come from generators offering power at $20 per megawatt-hour. The next 90 MW might come from generators offering $40. The final 10 MW needed to meet demand might come from a peaker plant offering $300. In most U.S. markets, the clearing price is set by the marginal unit, the last megawatt needed to meet demand. In this example, all 1,000 MW would be paid $300 per megawatt-hour.
Neel Somani of Eclipse explains that this is known as uniform clearing price or marginal pricing. Even generators that offered $20 receive $300. This structure is intentional. It ensures that:
The price reflects the cost of serving the next increment of demand, not the average cost of generation. This is why electricity prices can spike dramatically during periods of high demand. If the system must rely on very expensive generators to meet the final increment of load, that price applies to all dispatched generation.
What Are You Actually Trading?
Another source of confusion is what it means to “trade power.”
When companies trade electricity, they are not physically routing electrons from one plant to one customer. Instead, they are trading financial commitments tied to specific delivery locations and time intervals.
In many markets, prices are defined at specific nodes or zones on the grid. Congestion can cause prices to differ between locations. Neel Somani understands that traders may buy or sell contracts tied to these locations to hedge risk or speculate on price movements. Physical delivery and financial settlement are coordinated through the ISO or RTO. The grid operator ensures that supply and demand balance physically, while the market settles financially based on clearing prices.
Zonal and Nodal Pricing
Some markets use zonal pricing, where large geographic areas share a common price. Others use nodal pricing, where prices are calculated at thousands of individual points across the grid.
Nodal pricing accounts explicitly for congestion and transmission constraints. If a transmission line is congested, the price on one side may differ from the other. Neel Somani explains that this reflects the real physical limitations of moving electricity. Location matters. Electricity pricing is not uniform across the country, and it can vary significantly depending on local supply, demand, and transmission capacity.
Why the System Is Designed This Way
The U.S. power market structure evolved to balance three competing objectives:
Marginal pricing may seem counterintuitive, but it creates strong incentives for efficient operation and investment. High prices during peak demand signal the need for additional capacity or demand flexibility.
The Bigger Picture
Electricity markets are not arbitrary pricing systems. They are tightly coupled to physical realities. Power must be generated at a precise frequency. Supply and demand must match at every second. Transmission lines have limits. Generators have operational constraints. ISOs and RTOs solve massive optimization problems every day to coordinate these constraints while minimizing total system cost. The marginal megawatt sets the price not by accident, but by design.
Most misunderstandings arise from assuming electricity behaves like other goods. It does not. Neel Somani emphasizes that it cannot be stored easily, routed directly from producer to consumer, or averaged across time without consequence. The next time prices spike, or headlines reference “expensive power,” it is worth remembering: the price you see reflects the cost of the last megawatt required to keep the system in balance. And behind that price lies a continuously optimized market built to reconcile physics and economics in real time.
