With Northwest utilities considering changing how they buy and sell power, it is a great time to understand our current system and various electricity market options.
Utilities must source electricity at the moment it is used. When you flip your light switch, the electrons that power your lights may have been generated by your electric utility or purchased from another utility or an independent power producer. Utilities and other entities buy and sell power 24 hours a day, seven days a week to ensure that the supply of electricity constantly matches customer demand.
These transactions between power entities can be bilateral between two utilities or executed by a centralized operator among many utilities. They can be arranged long term, a day ahead, or in the moment. As we talk about market configuration and organization, we will consider four types: bilateral trades, real-time markets, day-ahead markets, and regional transmission organizations.
At the simplest level, a utility with a supply gap might purchase power directly from a neighboring utility or an independent power producer, which is a bilateral trade. The Northwest operates largely on bilateral trades as a decentralized market comprised of short-term and long-term individual agreements between entities. Prices vary with each agreement and are negotiated between the buyer and seller.
Bilateral trading expands resources available to individual utilities and is a key component of securing adequate power supply. However, it lacks the additional cost savings, reliability, and environmental benefits that come from a centralized market in which a non-utility market operator looks across a given region to dispatch the most cost-effective power supply.
The Western Energy Imbalance Market (WEIM) is one step toward a more centralized market for the Northwest. The WEIM is a “real-time” electricity market managed by the California Independent System Operator (CAISO) that addresses supply imbalances just before electricity is dispatched. It accepts supply bids from participants, matches that supply with demand imbalances, then clears the market for each 15-minute and 5-minute interval, optimizing for power transfers among all participating utilities and power producers at the lowest possible price. Each participant also continues to secure power through its own generation or bilateral trades for long-term or day-ahead purchases.
Participating Northwest utilities include PacifiCorp, Idaho Power, Portland General Electric, Puget Sound Energy, Northwestern Energy, Tacoma Power, Seattle City Light, and the Bonneville Power Administration (BPA), among others.
Since launching in 2014, the WEIM reports savings of $5.85 billion for participating utilities. The benefits are not only economic; the WEIM also reports 1 million metric tons of carbon emissions reduction by enabling renewable energy to be sent where it is needed in times of surplus, rather than being curtailed. The market has also become a key tool for maintaining reliability when demand is exceptionally high, such as during extreme weather events.
Looking to expand on the WEIM’s real-time market benefits, utilities across the Northwest are considering joining a day-ahead market. Day-ahead markets go further than real-time imbalance markets by facilitating optimized dispatch of power one day ahead of delivery.
This gives suppliers more time to plan for production and transmission providers more time to prepare for transmission line congestion. Day-ahead planning also allows for a much larger volume of transactions, resulting in greater economic efficiency and reliability benefits than a real-time market can produce.
In the Northwest, utilities are considering two day-ahead markets. One is offered by CAISO called the Extended Day-Ahead Market (EDAM). The other is Markets+ run by the Southwest Power Pool (SPP), a grid operator in the central United States interested in expanding westward.
While both markets offer similar services, there is a question in the region over which market offers greater benefits. A utility or producer’s decision—and particularly BPA’s decision—to participate in one of these day-ahead markets has a region-wide impact because it will change the scale and variety of available resources in the market’s geographic footprint. (Our next blog in this series dives deeper into the complexities of choosing between the two market offerings and why BPA’s decision is so consequential.)
At the most organized level, a group of utilities might belong to an electricity market that offers both a real-time and a day-ahead market and consolidates transmission operation and some regional planning. These markets are common across the United States, and the operators are known as ISOs (Independent System Operators) or RTOs (Regional Transmission Organizations).
An example of an ISO/RTO is the Midcontinent Independent System Operator, or MISO. MISO covers part of the Midwestern United States and Manitoba, Canada and serves as an air traffic controller of sorts for the electricity grid, providing one unified transmission system and a centralized, wholesale electricity market. Among its many responsibilities are maintaining reliability, allocating resources, operating transmission, and creating a competitive marketplace for electricity.
Other similar organizations exist in New England, the Mid-Atlantic, the central US, New York, California, and Texas. In addition to providing a marketplace for power, some ISOs/RTOs operate a capacity market, which pays producers for a commitment to provide electricity in the future if needed, in addition to the actual sales revenue they will receive for the electricity itself. ISOs/RTOs may also operate a market for ancillary services that ensure the reliability of transmission and distribution, such as frequency regulation and operating reserves.
There is no immediate plan to create an RTO in the Northwest. But pending the success of a day-ahead market, an RTO could be a future possibility.
Studies have repeatedly shown that a west-wide market— with participation not just from the Northwest, but from all 11 states in the Western grid—would maximize benefits for the region. In its deep decarbonization pathways modeling, CETI assumes a west-wide market to take advantage of the efficiencies gained by sharing resources across the greatest possible footprint. Whether or not that future materializes remains to be seen and depends largely on upcoming decisions by Northwest utilities and BPA.
Following up on this introduction to market structures, our next blog digs into the two proposed day-ahead markets being considered by Northwest utilities.
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