One key benefit of expanding high-voltage transmission is the cost savings potential of this vital infrastructure. Market competition and technological innovation drive those cost savings. In essence, the transmission grid is the physical platform that creates a technologically neutral, wholesale marketplace in the power sector. 

We’ll explore these concepts in four areas: the mechanics of economic dispatch, some history of the grid in the U.S., high-voltage transmission modeling study results, and real-world grid planning outcomes. These threads illustrate the importance of transmission expansion for leveraging market activity to save customers money, including across various possible future generation mixes.

The mechanics of economic dispatch

Electric grids are collections of generating units and customer loads (for example, homes and businesses using electricity) spread across a geographic area and strung together by a web of transmission lines. Each grid’s transmission network is designed so that the generators and loads on that grid are robustly interconnected. This means that any generating unit can inject power into the grid, and power can ultimately reach any load point, even those located hundreds of miles away. This interconnectedness sets the table for individual generating units to compete against each other to supply power to customers in a process called “economic dispatch.”

The U.S. Department of Energy describes economic dispatch as “…the practice of operating an electric system so that the lowest-cost generators are used first, followed by the more expensive generators. As demand increases, more expensive generators are brought into production, and then ramped down again when loads decrease.” A grid operator manages the generating units on the system to match the total electric generation to the customer load in real-time. Thus, generating units compete every hour, and the grid operator selects the lowest-cost units to serve the load. Importantly, this competition is technology-neutral: selection hinges on each generator’s ability to produce power in that hour and its price. 

A report by the PJM Interconnection, the wholesale power market and grid operator serving 14 states in the mid-Atlantic, explains that “Transmission assets tie PJM zones together. These assets enable competition among power producers by providing access to PJM’s wholesale markets for capacity, energy and ancillary services…A robust transmission system lowers the net costs of electricity to consumers by allowing the next most-cost-effective megawatt to be dispatched.” Economic dispatch is used in organized competitive markets, such as PJM, and by individual utilities in regions without organized markets, such as the Southeast and Interior West.

In practice, generators and loads are typically only partially interconnected into one large pool.  For example, as grid conditions change over the years, the transmission network can get out of sync with the locations of the generators and load points, and grid congestion ensues. Operators must reroute power flows when a low-cost generator doesn’t have access to a transmission line that isn’t already full. This prevents operators from using that generator to serve customers, forcing them to use a higher-cost generator instead. All of this means that, because competition among electric generating units is limited when the transmission network is not internally well-connected, customers pay more. 

Further, a similar dynamic happens across grids. For example, two adjacent grids like PJM and MISO (the grid operator for 15 states in the Midwest and South) can transact with one another to the extent they are connected through transmission. In some hours, MISO’s “next most-cost-effective megawatt” will be cheaper than PJM’s, while the reverse will be true in other hours. In either case, the two grids could simultaneously save their customers money by transacting with one another, broadening the pool of generating units competing to serve customers. These cost-saving transactions also work between individual utilities outside an organized market context and between a utility and an organized market. But again, this is only possible to the extent that transmission lines connect adjacent grids. 

Analyses of grid prices have quantified the potential for new transmission links to save customers money through enhanced market efficiency. Lawrence Berkeley National Laboratory used historical grid pricing data to calculate the price differences within and between grids, finding that “Many regional and interregional transmission links have significant potential economic value from reducing congestion and expanding opportunities for trade.”

U.S. grid history

On a longer timeline, a robust transmission network allows new generators to interconnect to the grid, enabling new technology and new firms to enter the market and begin competing to provide power to customers. We’ve seen this dynamic throughout U.S. history. Brattle Group researchers have documented how most of our existing transmission network was constructed many decades ago, including during an electric sector boom during the 1960s and 1970s that brought large amounts of coal, natural gas, and nuclear capacity online. The DOE has noted that early high-voltage interstate transmission was constructed to link large hydro generators to load centers, and that “some investor-owned utilities in the western United States built interstate transmission in the 1970s and 1980s to connect new large-scale coal plants that were sited near fuel supplies but far from major load centers. Some of these new lines passed through as many as three states.” 

Today, the grid initially built to host 20th-century technologies has served as a vital platform for market entry of more efficient combined-cycle natural gas plants and renewable generators like onshore wind and solar photovoltaics. These technologies have dominated new-generation construction this century due to technological development, cost declines, and policy support. Thus, transmission networks enable competition and innovation on a yearly and decadal scale while also supporting the hourly competition discussed above. Regarding all of these timescales, state utility commissions and organized market governance processes play crucial roles in assessing the value of transmission and ensuring transmission benefits flow to customers.

Modeling future transmission

Transmission modeling studies can help us forecast whether building more transmission lines in the coming years will further enable competition that minimizes customer costs. For instance, in one study example, NREL investigated transmission impacts using capacity expansion modeling, whereby advanced computer software finds the least-cost generation and transmission buildout combinations under various scenarios. The capacity expansion software identified significant transmission capacity needs across scenarios, including in the base case, where, in 2038, wind and solar generation remained below 30% of total generation, and fossil generation still played a significant role. This illustrates the value of additional high-voltage transmission across various generation mixes. Further, when an HVDC macrogrid (a nationwide, high-capacity, efficient transmission network) was included in the same base case, transmission capacity additions more than doubled. Still, overall costs decreased thanks to the more economically competitive generation. 

It’s worth underscoring the implications of “reduced overall costs.” While new transmission infrastructure adds system costs, thereby increasing certain components of customer electric bills, it simultaneously reduces other system costs and can more than offset those cost additions. The HVDC case in NREL’s study illustrates this point: $12 billion of additional investment enabled $15 billion in operational cost savings for a net savings of $3 billion. In this scenario of savings more than offsetting costs, customer bills would be lower than they would have been in a future where the new transmission isn’t built. While that does not necessarily mean electric bills wouldn’t rise over time, they would increase less than in a base-case future without additional transmission.

Relatedly, the DOE’s Transmission Needs study aggregated the results of many capacity expansion modeling studies. The Needs study’s capacity expansion analysis yielded numerous conclusions, for example, identifying insights specific to several different scenario groups. For the most conservative scenario in terms of future shifts in load and generation mix, the study concluded:

Capacity expansion modeling shows within-region transmission capacity-mile deployment across all contiguous U.S. regions needs to increase 14% by 2030 and 24% by 2040 (median results) to meet a future with moderate load and clean energy growth. The future power system described by this scenario group has less load and clean energy growth than that projected to be enabled by state and federal laws enacted since 2021….Interregional transfer capacity needs under these moderate scenario conditions are similar, needing to grow 14% by 2030 (median 16 GW) and 34% by 2040 (median 38 GW) nationally.

While other scenarios–namely, those with higher load growth or a more pronounced shift to clean energy–built out more transmission infrastructure, significant transmission expansion occurs even under scenarios with less load and clean energy than currently expected. This means the potential remains to reduce overall costs by further expanding the transmission grid in the coming years, even with moderate load and clean energy growth. Thus, while researchers will continue to undertake additional studies, and modeling methods are constantly improving, existing studies strongly affirm the expectation that expanding our high-voltage grid can further enhance market competition compared to today’s grid and offer cost savings even when assuming grid conditions only change modestly in the next 15 years.

Grid planning outcomes

MISO completed its most recent transmission planning process in 2022. The outcome identified $10 billion in transmission investments expected to yield a benefit-cost ratio of at least 2.6. Most of these benefits come from avoided congestion, fuel savings, and reduced generator capital costs, reflecting more cost-effective generation enabled by a more robust transmission network. During the planning process, the assumed generation mix in 2039 was 25% wind and solar, 58% coal and gas, and 11% nuclear. 

Planning efforts shouldn’t focus only on base case scenarios; in fact, good planning requires considering a wide range of future conditions. Currently, MISO is continuing its transmission planning process with additional phases that assume different future generation mixes, load growth, and other factors. However, similar to the modeling studies discussed above, MISO’s planning results illustrate that transmission additions save money through more fulsome market competition, even when generation mixes only shift modestly toward renewable energy.


By considering economic dispatch practices, power systems history, and recent modeling and planning results, we’ve seen how the grid enables competition among power generation technologies on every timescale, thus driving costs down for customers. The transmission grid is the marketplace at the wholesale level of the power sector. Expanding and strengthening high-voltage transmission infrastructure is a proven way to leverage markets to deliver benefits to society, and our policies and regulations should support the growth of these vital assets.