Descriptive Text of Value Chain Step
In our taxonomy of the “power markets” value chain, the wholesale market and transmission operations represent the bridge between supply resources (Generators) and load (users, aggregated by Load Serving Entities). We discuss wholesale and transmission primarily in the context of the Independent System Operator (ISO) / Regional Transmission Operator (RTO), but not all transmission and wholesale markets in the U.S. are organized this way.
For clarity, we divide the Wholesale Markets and Transmission Operations step into several parts: market making and optimization, operational activities, the physical infrastructure (the transmission and distribution lines themselves), and the ownership of that infrastructure. We break these roles out because they are not always bundled together under the same organization.
Market Making Activities
In places where an organized power market exists (an RTO or ISO in the case of the U.S.), the primary activities of the wholesale power market are to:
- Take bids from market participants (i.e., generators and LSEs) for energy and ancillary services (e.g., spinning and non-spinning reserves over various time-steps)
- Run a combined auction, optimized subject to all constraints, including: provided bids, capabilities of the resources involved, reliability requirements, transmission system limitations, transmission rights, etc. The output of these market optimizations and auctions are locational marginal prices (LMPs), which reflect the price of power at each location in the transmission network, accounting for transmission congestion and losses, as well as awards, which are the instructions to each generator for the amount of energy they are expected to generate over a specific period. The earnings of each generator is therefore the product of the award amount multiplied by the LMP at their point of interconnection.
- Publish resulting prices and award instructions for participants to execute based on the auction/optimization outcome. ISOs/RTOs have “same time” information systems to publish this information in a manner that all participants can access it simultaneously, so there is no advantage given to any participant (e.g., “OASIS” in PJM and CAISO). Instructions take the form of commitment (i.e., whether a generator needs to run during a given period) and dispatch (i.e., a schedule of output levels the generator is expected to meet)
- Publish and enforce penalties for deviations from published instructions (see, e.g., CAISO uninstructed deviation penalties).
In addition to running markets for energy and ancillary services, ISOs/RTOs also typically run a market for financial transmission rights (FTRs), which allow market participants to reserve transmission capacity. Some ISOs/RTOs also operate capacity markets, in which generators and LSEs bid capacity in order to make sure there are adequate reserves. Some ISOs, such as CAISO, do not have a capacity market, but LSEs still have to regularly demonstrate resource adequacy to their regulator.
The transmission infrastructure itself may be owned by independent transmission owners or by the utilities within the ISO/RTO territory. The Energy Policy Act of 1992 mandates fair and non-discriminatory access to transmission, regardless of whether the transmission is in an ISO/RTO or not. FERC Order 888 and 889 set similar requirements, and FERC Order 2000 encouraged utilities to turn over operation of their transmission to ISO/RTOs. The word “independent” in “ISO” refers to the fact that the wholesale market and transmission operator is not also a market participant. Transmission owners therefore cannot take advantage of the market power that a given link in the transmission network might have, nor can market participants that own both transmission and generation (or in the case of an IOU, load) operate the system for their own benefit.
There are large parts of the U.S. still served by vertically integrated utilities, which accounted for about 60% of electricity sold in 2016 in terms of MWh (calculated from EIA data ). In areas served by IOUs, wholesale and transmission activities do not happen explicitly in such a structured manner, though such utilities still have to determine which of their resources to deploy to meet load most economically subject to various system constraints.
Optimization: A typical market optimization aims to create a feasible dispatch to meet load at the lowest overall cost, subject to all the necessary constraints for operating the transmission safely and reliably. Focusing on other objectives besides lowest cost, such as lowest GHG emissions, is also theoretically possible.
There are many constraints that must be taken into account in market optimization. Laws and market rules limit the options available to a market operator. Bids supplied to the market result in price curves specifying the market-clearing price at possible levels of dispatch. There are physical constraints to the transmission system itself and to the capabilities of the generation resources; transmission is further constrained by various market participants’ transmission rights. Additionally, there are reliability constraints to consider, such as “N-1” or “N-1-1” constraints that specify that if the largest generation and transmission resource should fail, the system should continue to operate. All of these constraints are fed into a computer to run a Security Constrained Unit Commitment (SCUC) and Security Constrained Economic Dispatch (SCED) optimization to generate LMPs as well as commitment and dispatch instructions. This process is repeated for various forward periods (e.g., day-ahead, hour-ahead, etc.) and time intervals (e.g., daily, hourly, etc.) The specific intervals and forward periods used vary by the particular market.
System Planning: Another important activity that wholesale market and transmission operators participate in is transmission and system planning. Typically, in such processes, the transmission operator is but one stakeholder in a process including transmission owners, generators, LSEs, advocates, and citizens, who determine when and where new transmission and other resources are needed. System planning is driven by conceptually similar models to those used for regular market optimizations, but including predictions and assumptions about load growth and migration, unit retirements, etc., and looking at longer time horizons. Planning results in the identification of needs, but system planning does not automatically result in transmission investment; ultimately, potential owners of transmission lines will make their own decisions regarding whether to invest.
The optimized results of the wholesale market must be relayed to market participants as dispatch and commitment instructions, and the transmission operator must monitor all participants to ensure they are behaving as expected. If they do not, dispatch instructions to them and other participants may be revised. Transmission operators also monitor the performance of the transmission system to see that everything is running within normal bounds and appropriate margins.
The transmission system is large, complex, and moves enormous amounts of energy at high voltages. As such, it requires constant monitoring, maintenance, and adjustment. In addition to control room operators, there are also field operations personnel who service remote equipment and make adjustments to the system that cannot be done through remote commands.
The physical infrastructure of the wholesale market and transmission operations is primarily the transmission system itself. The essential elements of the transmission system are towers, lines, transformers, switchgear, protection equipment, and other related equipment necessary to convey power. Also essential are control systems and telemetry, which allow the system operator to monitor the state of the system and issue commands to manage it (e.g., open and close interconnections, change transformer taps, add or remove capacitor banks, etc.). In the industry this is called “supervisory control and data acquisition (SCADA). The types of data gathered by the SCADA system include switch positions, current, and voltage flows. A relatively new source of telemetry is the Phasor Measurement Unit (PMU), which can provide very accurately time-synchronized current and voltage measurements from different locations on the transmission system, allowing operators to understand the phase relationship between them and better monitor the power flows.
In addition to the transmission equipment itself, there are also control rooms and displays used by operators. To support the market-making function, there are also computer systems and software to take bids, transmit market results to participants, and perform the required market optimizations.
Actual ownership of the transmission system itself varies. In ISO/RTO territories, ISOs/RTOs generally do not own the transmission that they manage. Instead, it is owned by utilities and independent transmission owners that have handed over the resources to the ISO/RTO to manage. The ISO/RTO then charges customers a tariff for the use of the system, and the owners are paid a return. There can be many owners of transmission lines under a given RTO/ISO’s control. In the un-deregulated vertical utility model in non ISO/RTO areas, the utility is likely to own the transmission as part of its ratebase. Even in ISO/RTO areas, utilities typically own much of the transmission and participate heavily in planning decisions. However, rules such as FERC 717, limit the ability of organizations with power market and transmission ownership functions to coordinate those functions for their benefit. For example, knowing that a transmission investment was or was not going to be made is useful information to someone making energy market transactions. As such, this order essentially puts up an internal “wall” between market and transmission planning functions within an organization that does both.
Figure DI.1 Map of Wholesale Electric Power Markets
Source: United States Environmental Protection Agency Website (https://www.epa.gov/greenpower/us-electricity-grid-markets), original data from FERC
Figure DI.2 Map of North American Electric Power Grids
Source: United States Environmental Protection Agency Website (https://www.epa.gov/greenpower/us-electricity-grid-markets)
Figure DI.3 Spectrum of Electricity Markets
Source: Department of Energy Electricity System Overview Appendix, original data from EPSA Analysis: Pace Global, Characterization of Regional Electric Markets