Part 1 of this series delivered a brief overview of the electric grid in the U.S. and looked at the history of the New York Independent System Operator (NYISO) in particular. In part 2, we will examine some of the details involved in the pricing of electricity on NYISO’s statewide competitive wholesale power market.
The demands placed on New York’s grid are substantial. A record peak load in the state of 33,956 megawatts occurred in July 2013 at the conclusion of a week-long heat wave, and an annual average of $7.5 billion in electricity and related products is traded on the state’s markets. To ensure power is affordable for consumers, while providing fair compensation for suppliers, NYISO conducts a range of processes to reliably match power supply with demand.
The price of electricity in the NYISO wholesale electricity market is established based on a methodology known as locational based marginal pricing (LBMP), in addition to a two-settlement process with day-ahead and real-time bid markets. The ultimate result is the dispatch of power from hundreds of power plants across the state, to businesses and retail consumers, governed by a base point signal from NYISO every six seconds.
Under the LBMP system, electricity prices are set by determining the cost to supply the next increment of load at each location in the state transmission system. The NYISO market directly schedules energy sales and purchases, with bids to purchase energy provided by load serving entities (LSEs), and offers to sell energy provided by power suppliers. The price of energy is the market clearing price, which takes into account bids and offers as well as physical aspects of the transmission system.
The LBMP scheme has three main components: energy, losses, and congestion. The energy component is the cost of electricity offered by suppliers. Losses occur when power is lost as dissipated heat due to the electrical resistance of power line conductors. Lastly, congestion refers to limits that are dictated by the power transmission capacity of the high voltage electricity lines that form the backbone of the grid. To maintain reliability of the system, these limits cannot be exceeded.
The LBMP method takes into account the physical location of power injection at generator buses, as well as loads consuming power in various zones of the state. If a supply in one zone represents the cheapest energy available, but needs to pass over transmission lines into a distant zone to meet a load, the transmission limits of the lines must be obeyed. If those limits would be exceeded, a different supply must be selected, resulting in a “congestion cost,” since the cheapest supply could not meet the load due to the physical limitations of the grid.
The locational based marginal price of energy is established for both markets in the two-settlement system. This process generates the schedule of electricity resources produced by power suppliers that will be consumed by load serving entities.
The two-settlement system consists of a day-ahead market and a real-time market. The day-ahead market allows energy to be bought and sold the day prior to actual consumption, establishing a financially binding schedule of production and consumption. The real-time market balances the day-ahead schedule with actual energy usage, allowing NYISO to dispatch electricity at a real-time price to fill any gaps between expected energy use and actual demand.
In the day-ahead market, a software package known as Security Constrained Unit Commitment (SCUC) determines the winning day-ahead bid selections. This package performs successive iterations to decide the least cost solution that meets reliability requirements, taking into account day-ahead bids, offers, forecasts, and transmission limitations. A day-ahead schedule of commitments is output by the SCUC.
This schedule of commitments then enters the real-time market portion of the settlement system known as the Real-Time Scheduling (RTS) system, which is comprised of two parts. The first segment of the RTS – the Real-Time Commitment (RTC) program – accepts real-time bids up to 75 minutes prior to the operating hour and executes an evaluation similar to the SCUC but on a shorter timescale to produce binding unit commitment schedules.
The second piece of the RTS is Real-Time Dispatch (RTD). The RTD program uses the same set of bids and constraints considered by RTC, and makes dispatching decisions every five minutes. It computes real-time market prices for energy and establishes real-time schedules for power dispatch, operating reserves, and regulation services.
The five-minute look-ahead base point dispatching decisions generated by RTD are passed on to the Automatic Generation Control (AGC) program, which dispatches a signal every six seconds to individual generators in the New York Control Area. The AGC signal ensures power system reliability by maintaining a constant operating frequency throughout the control area.
NYISO’s locational based marginal pricing scheme and two-settlement market system ensure that electricity is delivered reliably at competitive rates to the state’s millions of businesses and residents.