In the United States, there are more than 8,800 power plants, nearly 160,000 miles of high-voltage power lines, and millions of low-voltage power lines and distribution transformers in the power grid. In order to efficiently and economically manage large power grids for their safe and reliable operations, wholesale and retail markets have been formed throughout the country. Several competitive wholesale markets in the United States are operated by the Independent System Operators (ISOs) or Regional Transmission Organizations (RTOs), such as Midcontinent Independent System Operator (MISO), California ISO (CAISO), Electric Reliability Council of Texas (ERCOT), New York ISO, New England ISO, and PJM Interconnection (PJM).
Among these markets, the wholesale market administrated by PJM is the largest. It coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia. Its area of operation is one of the most densely populated and industrialized regions of the country, and it serves over 65 million people. With over 21 % of the U.S. Gross Domestic Product (GDP) produced in its region, the PJM's summer peak load can hit 165.49 GW with a generation capacity of over 185 GW.
Source: Electric Power Markets, National Overview, https://www.ferc.gov/electric-power-markets
Since the supply and demand of the electricity in the power system must be matched in real time, a two-settlement system including a day-ahead (DA) market and a real-time (RT) market is designed and operated by RTOs and ISOs. The two-settlement system can better arrange the generating resources to meet the anticipated and instantaneous power demands and determine the financial charges and credits to the market participants.
In the DA market, the demand bids and supply offers submitted by the market participants are used to determine an economic dispatch and calculate the next-day hourly locational marginal prices (LMPs), also called DA LMPs. As the instantaneous generation and load always deviate from the DA scheduled, the RT balancing of supply and demand is performed by RTOs and ISOs in the RT market and 5-min LMPs are calculated simultaneously based on the actual operating conditions and economic dispatch. Afterward, the 5-min LMPs will be integrated into hourly RT LMPs to determine the financial settlement.
Given the demand bids and supply offers, the LMPs can be obtained via the dispatch optimization programs which makes the system demands be served safely and reliably at the least cost. The LMPs are combined with three pricing components: system energy price, transmission congestion cost, and marginal loss cost. These components make the LMP reflect the marginal cost of delivering an additional unit of energy to a specific location, such as a city, a power plant, and an aggregated load zone, in the power system. (In the DA market, the 24 hours DA LMPs are determined based on the generation expectations and the anticipated loads for the next day. Compared to the RT LMPs, lower price volatility of DA LMPs is expected while the RT LMPs are in influenced in the RT market by the updated bids, deviations between anticipated and actual loads, transmission, and generation outages, etc.)