How Does Electricity Actually Move? A Grid Fundamentals Primer

Every conventional power plant — whether it burns natural gas, splits atoms, or catches wind — does fundamentally the same thing: it spins a shaft connected to a generator. Inside that generator, large magnets rotate past coils of copper wire. When a magnetic field moves past a conductor, it pushes electrons. That electromagnetic interaction is the basis of nearly all grid-scale electricity production.

A natural gas turbine burns fuel to spin the shaft directly. A nuclear plant boils water into steam that drives a turbine. A wind turbine lets the atmosphere do the spinning. Solar panels are the exception — they produce electricity through the photovoltaic effect rather than mechanical rotation — but the grid handles their output the same way once it reaches the transmission system.

Generating electricity means converting some form of energy (heat, motion, sunlight) into the movement of electrons through wire. The grid is the system that moves those electrons from where they are generated to where they are consumed.

The electrons in a power line do not travel in one direction. They vibrate back and forth, 60 times per second in North America. This is alternating current (AC).

Direct current (DC) pushes electrons in one steady direction — like a battery. Early electrical systems used DC, and it works well over short distances. But AC won the infrastructure war for one critical reason: voltage can be easily changed using a transformer, and voltage is the key to moving power efficiently over long distances.

Electrical power equals voltage multiplied by current. To deliver 100 MW, the system can push a massive amount of current at low voltage, or a small amount of current at high voltage. The total power delivered is the same. But current generates heat in the wire (I²R losses), and heat means wasted energy. Double the current, quadruple the resistive losses.

For long-distance transmission, the solution is to push voltage as high as possible and keep current as low as possible. Transformers make this straightforward with AC — step voltage up to 345,000 volts for transmission, step it down to 13,800 volts at a substation near the load center, step it down again to 480 volts or 120/240 volts at the point of use.

With DC, changing voltage historically required expensive and lossy conversion equipment. Modern high-voltage direct current (HVDC) technology has made DC economical for specific applications — undersea cables, very long point-to-point corridors, and interconnecting asynchronous grids — but the vast majority of the grid remains AC because transformers are cheap, reliable, and have been the backbone of power delivery for over a century.

Voltage is the electrical equivalent of pressure — the force that pushes electrons through a conductor, analogous to water pressure pushing water through a pipe.

Higher voltage allows the same amount of power to be delivered through a thinner conductor with less loss. This is why transmission lines — the tall steel towers crossing the countryside — operate at very high voltages: 138 kV, 230 kV, 345 kV, and in some cases 500 kV or 765 kV.

End users do not receive power at transmission voltage. Between the transmission system and the point of use, voltage is stepped down through a series of transformers:

Transmission (345 kV) → Sub-transmission (138 kV or 69 kV) → Distribution substation (13.8 kV or 34.5 kV) → Service transformer (480V, 240V, or 120V)

The North American grid operates at 60 Hz — the alternating current completes 60 full cycles per second. Every synchronous generator within an interconnection is locked together at this frequency. A two-pole generator spins at 3,600 RPM; a four-pole generator at 1,800 RPM. All of them are synchronized.

When demand exceeds supply, generators experience increased electrical load, causing rotors to slow down. Frequency drops below 60 Hz. When supply exceeds demand, generators speed up. The grid operator detects deviations within milliseconds and dispatches generation to restore balance.

Inertia and the Inverter-Based Resource Challenge

The massive multi-ton steel rotors in conventional generators provide inertia — stored kinetic energy that buffers against sudden frequency changes. When a large generator trips offline, the stored rotational energy in every other spinning generator temporarily compensates, buying seconds for automatic controls to respond.

Solar and wind resources connect through inverters rather than synchronous generators. They have no spinning mass and contribute zero physical inertia. As the generation mix shifts toward renewables, total system inertia declines — the grid's frequency can change faster in response to disturbances, leaving less time for corrective action.

One emerging solution is the grid-forming inverter — battery or renewable inverters that synthetically mimic inertial response by rapidly injecting or absorbing power during frequency deviations. This technology is in early commercial deployment, and several ISOs (including ERCOT) are developing requirements for grid-forming capability on new interconnections.

The electrical grid has three distinct layers:

Generation — Power plants of all types: gas turbines, nuclear, coal (declining), wind, solar, and battery storage. Generators connect at the transmission level. ERCOT, for example, has roughly 150 GW of installed capacity across all resource types.

Transmission — The high-voltage backbone. Steel towers and underground cables carrying 138-765 kV lines over long distances. Transmission moves bulk power from generation sources to load centers. ERCOT has approximately 53,000 miles of transmission lines. Transmission is planned and regulated by ISOs/RTOs (Independent System Operators / Regional Transmission Organizations) and state or federal regulators.

Distribution — The local delivery network. Wooden poles and underground cables carrying 4-34.5 kV to neighborhoods, commercial buildings, and small industrial facilities. Distribution is typically owned and operated by the local utility.

Transmission lines have physical limits. Push too much current through a conductor and it heats up, expands, and sags toward the ground. These thermal limits define the maximum power a line can carry.

When the most efficient delivery path is at capacity, the grid operator must re-route power through longer, less efficient paths — or dispatch more expensive local generation instead of importing cheaper power from farther away. This condition is called congestion.

Congestion is not a system-wide phenomenon. It is locational. Two buses 50 miles apart can experience very different congestion depending on which transmission lines connect them and how loaded those lines are. Congestion patterns shift hour by hour as load and generation change.

In deregulated wholesale markets (ERCOT, PJM, MISO, SPP, NYISO, ISO-NE, CAISO), electricity is priced at every bus (node) on the transmission network through Locational Marginal Pricing (LMP):

LMP = Energy Component + Congestion Component + Loss Component

• Energy component: The marginal cost of serving the next MW of load system-wide, typically set by the fuel cost of the marginal generator.
• Congestion component: When a transmission constraint binds, the system must dispatch out-of-merit generation. The congestion component captures this cost differential. Two buses on opposite sides of a binding constraint can diverge by $20-50/MWh or more.
• Loss component: Energy lost as heat during transmission. Buses far from generation sources incur higher marginal losses. Typically small relative to energy and congestion.

LMPs are calculated every five minutes (real-time market) or hourly (day-ahead market). They signal where power is cheap and where it is expensive, guiding generation dispatch, load siting, and transmission investment decisions.

Basis Risk

Basis is the price difference between two nodes. Any contract referencing a price at one node while physical delivery occurs at another is exposed to basis risk. If congestion drives the delivery node's LMP above the contract node's LMP, the contract provides less economic hedge than expected. Basis risk is a function of grid topology and congestion patterns — it is locational, not market-wide.

Adding new generation or large load to the grid requires a formal interconnection study — an engineering analysis conducted by the ISO/RTO or transmission owner to determine whether the existing infrastructure can accommodate the new resource without violating reliability criteria.

The study evaluates three primary dimensions:

1. Thermal capacity: Will the new injection or withdrawal overload any transmission lines or transformers?
2. Voltage stability: Will voltages at nearby buses remain within acceptable ranges under normal and contingency conditions?
3. Short-circuit adequacy: Does the bus have sufficient fault current to support the interconnection?

If violations are identified, the interconnection customer is typically assigned the cost of network upgrades — new lines, transformers, substations, or protection equipment. These costs can range from negligible to hundreds of millions of dollars depending on location and size.

The electrical grid is a continent-spanning machine governed by the physics of electromagnetism, the thermal limits of conductors, the mechanical dynamics of spinning generators, and the economic signals of nodal pricing. Electricity is generated by converting energy into electron flow, transmitted at high voltage to minimize losses, delivered through a layered network of infrastructure, and priced at every node based on marginal cost, congestion, and losses.

Understanding these fundamentals — voltage, frequency, inertia, congestion, and LMP — provides the foundation for evaluating any question about where to site generation, where to interconnect load, and how the grid will respond.