American Electricity Production
A description of the logistical and political organization of American electricity production.
Contents
Vertical Integration
Until the 1990s, electricity production and transmission was a vertically integrated market. Utility companies generated electricity and delivered it to customers. Customers paid a rate determined by their contract. The grid was regulated by the Federal Energy Regulatory Commission (FERC).
Such utilities established pools to share supply. These mitigated risks from unanticipated demand fluctuations, as well as from any events that can impact supply (e.g., weather). These also enabled the shifting of production to generators that are relatively cheaper to operate.
For these reasons, continental interconnections emerged to cover all of the United States and Canada. There are principally only four power grids:
- Western Interconnected System
- Eastern Interconnected System
- Texas Interconnected System, i.e. the Electric Reliability Council of Texas (ERCOT)
- Quebec Interconnected System
Markets
In the 1990s, the power grid was deregulated at the federal level. Some states maintain regulations, but several structural changes have emerged universally:
- electricity transmission and electricity production are separated
- customers pay a rate determined by a market
Importantly, the four power grids remain from the vertical integration era.
There are generally three types of electricity markets operating.
Day-Ahead Market
For the most part, electricity supply and price are determined in a day-ahead market. These generally operate at the hourly level.
Electricity producers submit a capacity and a market rate. Regional transmission organizations (RTO) select a bundle of producers to minimize costs while meeting demand.
A simplified model looks like:
Producer |
Capacity |
Rate |
A |
1,200 MW |
$20/MWh |
B |
400 MW |
$30/MWh |
C |
500 MW |
$0/MWh |
For a given demand of 2,000 MWh, the optimal bundle is Producer C at 100% capacity, Producer A at 100% capacity, and Producer B at 80% capacity. The clearing price is set at the margin, i.e. $30/MWh.
This is a simplified model because...
- producers do not have perfect flexibility to provide any arbitrary capacity
- prices are not necessarily linear
- demand must be predicted
Wind and solar producers often set zero or negative rates because they have no input costs, have maintenance costs regardless of connection status, and generally benefit from governmental subsidies paid according to MWh produced.
Real-time Market
Unanticipated shortfalls and overages from the day-ahead market are managed by a real-time market. This captures fluctuations in both demand and supply. For example, if a wind producer fails to meet the capacity they sold on the day ahead market, they will purchase their shortfall in this market.
Generally the rates used in this market are higher.
Capacity Market
In most states, there is also a capacity market that incentivizes excess capacity. Producers are paid regardless of whether or not their production is connected.
This is largely driven by regulations requiring RTOs to purchase enough capacity for demand plus some margin.
Notably, the Texas grid does not operate a capacity market.
State Regulations
Not all states deregulated the power grid, and several chose partial deregulation.
Totally deregulated states allow customers to sign contracts with electricity producers directly rather than the local transmission company. This can enable more predictable rates (bearing in mind that transmission rates are non-negotiable) and can enable preferential selection of producers (e.g., renewable producers).
A common partial deregulation pattern is the establishment in wholesale markets, but the maintenance of transmission monopoly (i.e., customers cannot sign a contract with producers).
Some states maintain the vertical integration of the power grid. Some of these states still participate in interstate wholesale markets, purchasing or selling capacity as a single entity.