The United States’ electric transmission and distribution grid is one of the largest and most complex systems in the world. With over 100 years of operation, the nation’s power grid connects more than 25,000 electric generators with 5 million miles of transmission and distribution lines, spanning 180 million power poles. This critical infrastructure is relied upon to provide around-the- clock energy to industry, commercial buildings, and more than 100 million households 1. However, current energy demands are ramping up while our distribution system is winding down due to overreliance on older, less efficient technology. The old age of our grid is struggling to accommodate the energy demand of large industry and data centers as most of the grid infrastructure was built in the mid-20th century during a similar period of rapid growth after widespread adoption of air conditioning 2. Distribution system transmission lines have a service lifespan of fifty to eighty years, and power poles typically last between thirty and fifty years 3. When transmission and distribution infrastructure is utilized far beyond its expected useful life, reliability can suffer, and cost-saving opportunities can be missed.
Maintaining the integrity of our bulk power grid requires wrangling transmission lines across regions, burying previously hanging lines, installing smart, automated lines, or bolstering line strength through facility and material upgrades. Additionally, vertical structures such as utility poles and pylons are replaced with new, treated wooden poles or hardened, reinforced materials such as steel or concrete 4.
This process of maintaining and upgrading the grid is much like sailing an aging ship while replacing it board by board. In this analogy, one could say that those captaining the ship are the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC). FERC and NERC provide oversight to ensure power is reliably delivered to customers. The crew of the proverbial ship is comprised of the balancing authorities, who make plans to repair and replace each board, and make upgrades needed to meet future demand.
Analogies aside, our modern grid requires rigid regional divisions to efficiently and effectively coordinate power generation and distribution. The contiguous United States really has three separate grids, known as “interconnections” 5. These three interconnections are the Eastern Interconnection, the Western Interconnection, and the Electric Reliability Council of Texas (ERCOT), and there is very limited transmission capacity connecting them to each other 6. NERC further subdivides the three interconnections into 10 separate transmission regions for reliability planning 7. These regions contain a total of 66 balancing authorities 8.
A balancing authority is an entity that operates either as a utility, a power marketing administrator, or a group of utilities that have formed either a Regional Transmission Operator (RTO) or an Independent System Operator (ISO) 9.
The U.S. Department of Energy’s four power marketing administrators –the Bonneville Power Administration, the Southeastern Power Administration, the Southwestern Power Administration, and the Western Area Power Administration – were created to sell wholesale power from federally owned hydroelectric dams (and later other types of power plants) to retail service providers, like rural electric cooperatives. This centralized approach to energy marketing was designed for federally owned generation facilities to sell and serve electrical power across distinct geographical territories, each spanning across multiple state boundaries, for the purposes of providing electrical services in rural and farming communities. The Southeastern Power Administration (SEPA) is unique out of the four power marketing administrators as it does not own or operate any transmission facilities 10. Instead, private, state, and local entities handle all federal transmission functions within SEPA.
ISOs and RTOs
In a similar top-down formation, ISO emerged from the FERC 888 and 889 orders, which was designed to prevent discriminatory and preferential access to transmission. Later, FERC Order 2000 encouraged regions to form RTOs. ISOs’ and RTOs’ primary objective is to oversee interstate transmission and large generation. Both FERC orders set the backdrop for our current electrical grid network. Multiple regions across the United States joined together, forming alliances between states through regional planning and implementation.
Take the Midwestern ISO (MISO), the nation’s first independent transmission operator, which stretches from Louisiana to Minnesota. Before forming in 1998, this region was a decentralized patchwork of multiple transmission-owning utilities. However, the utilities recognized that a singular system control operator would yield a more effective and seamless functionality of its independent systems. These utilities, joined MISO, effectively handing over the functional control of their transmission grid. Like a call and response instructed by a conductor to their orchestra, MISO creates electrical harmony across its 15-state footprint, coordinating constantly around the clock, waving its baton to its constituent members on who should turn the knobs and flip the switches in order to facilitate communication within the midcontinental region.
Within RTOs and ISOs, wholesale electricity markets were created for the purposes of facilitating electric trade between generators and customers. Given that the grid is a continuously operating machine, multiple markets are set up to allow for real-time, next day, and annual capacity trading. Similar to MISO member utilities, these markets are closely linked together and feed off of each other’s information, creating a dynamic relationship between energy trading at the level of seconds and a single year.
However, not all of the contiguous U.S. congealed into an RTO or ISO. Notably, the vertically integrated model still exists in parts of the West and most of the Southeast. Southeastern states allow electric utilities to operate as monopolies, thus granting utilities complete ownership for all points of the grid (generation, transmission, and distribution). This concentration of power necessitates government oversight to ensure fair and responsible operation.
South Carolina’s balancing authorities include the four vertically integrated utilities: Dominion Energy South Carolina, Duke Energy Carolinas and Duke Energy Progress, and the state-owned power authority Santee Cooper 11. Santee Cooper sells most of its power to electric cooperatives, but it also directly serves retail customers in parts of Horry, Georgetown, and Berkeley Counties. All four of South Carolina’s balancing authorities operate as vertically integrated monopoly utilities. This means that they have exclusive access to a service territory and own and control the entire electricity supply chain, from power plants to transmission lines and distribution lines.
For electricity distribution, monopolies are a more cost-effective option than having separate companies with redundant power lines running down the same streets and competing for customers. A monopoly utility puts up a single line of distribution lines on each street and spreads fixed costs over more meters, allowing for lower rates.
NERC & SERC
NERC is a private entity that develops reliability standards, while FERC has regulatory authority over interstate transmission planning and sets open access transmission tariffs (OATTs) that owners of transmission lines can charge for use of their lines. Since 1968, NERC has developed and enforced standards for electricity planning operations, monitoring grid performance, and assessing forecasts and auditing owners, operators, and users12. Operational standards are established in the Reliability Standards and Regional Reliability Standards, which are approved by FERC. NERC also develops Transmission System Planning Performance Requirements (TPL-001-5). Planning performance requirements establish13.
In addition, NERC operates the Electricity Information Sharing and Analysis Center (E-ISAC) 14. The Center communicates grid stability and safety information to mitigate digital and physical security threats and avoid service disruptions. South Carolina falls within NERC’s Southeastern Electric Reliability Corporation (SERC) region15. It includes all or portions of Florida, Georgia, Alabama, Mississippi, Louisiana, Texas, Oklahoma, Arkansas, Missouri, Iowa, Illinois, Kentucky, Tennessee, Virginia, North Carolina, and South Carolina16. The SERC-registered balancing authorities in South Carolina are Duke Energy, Dominion Energy South Carolina, and Santee Cooper.
FERC
In 1977, the Department of Energy Organization Act granted FERC regulatory authority of over interstate electricity transmission, wholesale exchange of electricity and natural gas, and the development and operation of interstate pipelines. Intrastate electric transmission and distribution falls under state authority, in accordance with the Interstate Commerce Clause of the U.S. Constitution. The principal regulator of our state’s electric utilities is the South Carolina Public Service Commission (PSC), which has authority over retail rates, capacity expansion planning, and more.
In 2023, FERC issued Order 1920, which builds on existing requirements from FERC Order 1000, which transmission providers must follow in conducting long-term regional transmission planning processes. In these planning processes, regional balancing authorities work together to lay out future supply-and-demand scenarios, conduct power flow modeling to evaluate potential transmission system upgrades to alleviate congestion, and evaluate contingencies to address reliability risks, such as power plant outages and extreme weather. Transmission lines can only handle a certain amount of power before they experience what is known as a “thermal violation,” and power flow modeling helps planners figure out how to cost-effectively mitigate the risk of thermal violations.
SERTP & SCRTP
FERC’s regional transmission planning regulations are implemented in the Southeast by three separate entities: Southeastern Regional Transmission Planning (SERTP), South Carolina Regional Transmission Planning (SCRTP), and the Florida Reliability Coordinating Council (FRCC).
These planning bodies are meant to provide an open and transparent planning process that fairly balances the needs of the separate transmission providers within their region. These processes include opportunities for stakeholder engagement, which the Coastal Conservation League participates in to help facilitate a cost-effective clean energy transition. Regional transmission planning horizons extend up to 20 years and include several potential scenarios in which different reliability and cost risks are considered. Regional plans are assessed based on their specific benefits, efficiencies, and cost-effectiveness, and include an evaluation process to select specific long-term regional transmission facilities. Beyond this, these entities determine cost-sharing arrangements for transmission facilities that benefit multiple transmission providers. In May 2024, the Federal Energy Regulatory Commission (FERC) finalized its long-term regional transmission planning and cost allocation rule known as FERC Order 1920 17.
Opportunities for Improvement
The Southeast has generally lagged behind other regions of the United States when it comes to transmission planning best practices. As a result, Order 1920 will disproportionately benefit electric ratepayers in the Southeast by strengthening federal requirements to align more with leading transmission planning regions.
Unfortunately, vertically integrated monopoly utilities tend to resist building more regional transmission capacity connecting their systems to other utilities because it is more profitable to rely on generation that they own rather than bringing in power from another provider. However, more regional connections, and especially smart planning that evaluates multiple benefits, can provide significant reliability and cost benefits for ratepayers. One reason for this is that energy demand fluctuates partly due to weather, and being able to bring in power from areas with low demand is often cheaper and more reliable than firing up expensive-to-run “peaker” plants. According to a recent study by the Brattle Group, ratepayers in the Southeast could save billions of dollars per year through improved transmission planning practices. More proactive transmission planning can also alleviate lengthy wait times and costly interconnection charges for solar developers, thereby accelerating a cost-effective clean energy transition that is good for ratepayers, communities, and the environment.