The US Electric Power System Infrastructure and Its Vulnerabilities (2025)

The US power infrastructure is one of the largest and most critical infrastructures in the world. The country’s financial well-being, public health, and national security depend on it to be a reliable source of electricity to industries, commercial entities, residential facilities, government, and military organizations.

Considering the complexity and age of most of the equipment in the US power infrastructure, the lifetime reliability is extraordinary—and it has improved in the last ten years (NERC 2017). Future system reliability may be challenged, however, by the effects of climate change, increasing supplies of renewable energy, and potential cyberattacks.

Background

There are three primary types of utility owner/-operators: investor-owned (IOU), publicly owned (California Energy Commission 2016), and cooperative (https://www.electric.coop). Unlike countries with a nationalized electricity supply system, the US system requires support from ratepayers, shareholders, and taxpayers to fund upgrades and improvements.

The overarching challenge for the US power system is how to maintain or replace the aging infrastructure, given the diverse set of owners/operators and financing mechanisms. In contrast to the high-tech sector, where the turnover of technologies is measured in months and characterized by high agility and potentially high profit margins, the electricity system is characterized by a capital stock turnover rate measured in decades, low agility, and small, regulated profit margins. The successful nexus of these very different sectors requires close cooperation.

Power Generation

The oldest generators are mostly hydropower and date from the 1940s or before. Most coal-fired plants date from the 1970s and ’80s, and nuclear plants were built between the late 1960s and 1980s. The most recent growth is in natural gas and renewable plants since 2000.

The states have the means and the authority to mandate cleaner generation, and there is a concerted effort by most to reduce reliance on fossil fuels: 37 have -adopted either renewable portfolio standard (RPS) laws or voluntary RPS targets to increase the level of renewable electricity generation (NCSL 2017); the standards and goals range from 2 percent (South Carolina by 2021) to 100 percent (Hawaii by 2040). Recently, New York and Illinois included nuclear-generated electricity in their goals to reduce carbon emissions (NEI 2018); other states, including Wisconsin and New Jersey, are considering similar legislation. The state-level RPS efforts are successful, as shown in figure 2.

High-Voltage Transmission System

Components of the System

The US electricity supply system has more than 600,000 circuit miles of alternating current (AC) transmission lines, of which 240,000 operate at high voltages (i.e., >230 kilovolts, kV).[2] This extensive structure is necessary to move the electricity from the bulk generators to the load centers and to provide the redundancy and diversity required to ensure reliable electric power for all customers.

This high-voltage transmission system (HVTS) comprises towers and conductors and a large number of transformers, circuit breakers, switches, and control systems. Much of the latter equipment is in 70,000 or so substations (DOE 2015) at the generating source, along the HVTS (to maintain voltage and flow), at the load centers, or in the distribution systems (discussed below).

How the System Works

The flow of electricity in the supply system requires an array of substations. High-voltage substations connect and stabilize the high-voltage transmission systems. The electricity is generated at less than 34 kV, but the HVTS operates at a much higher voltage to minimize transmission line losses, so a step-up substation is required. To connect with the load centers, step-down substations then reduce the voltage to less than 69 kV and feed into distribution substations, which transmit electricity to the consumer. A few converter substations convert the high-voltage AC to high-voltage DC for the regional interconnections.

The high-voltage transformers, particularly those of 345 kV and above, are critical to the proper functioning of the electric system. In the US HVTS there are about 2,100 transformers rated at 345 kV and above (DOE 2015). Such transformers are very expensive ($2–$7.5 million each), large (up to 56' wide × 40' long × 45' high), and heavy (up to 410 tons); have very long lead times for procurement (typically 24 months); and are traditionally custom designed for each application for maximum efficiency. Generally, there are few, if any, spare transformers with ratings above 345 kV in utilities’ storage yards. Like most of the US electricity supply system, most of these large transformers are near end-of-life design conditions (DOE 2012).

The operation and planning of the HVTS in the United States have evolved in most areas from control by traditional, vertically integrated utilities to either regional transmission operators (RTOs) or independent system operators (ISOs); all three types are subject to the rules of the Federal Energy Regulatory Commission (FERC 2018). An ISO operates the high-voltage electricity grid, administers the region’s wholesale electricity market, and provides reliability planning for the region’s electricity system. RTOs have a similar role, but have more authority and responsibility for coordinating, controlling, and monitoring the operation of their region’s transmission system.[3] There are still US regions where vertically integrated utilities exist; for example, in the West and the Southeast they still control about 40 percent of US electricity.

Changes in the HVTS

There are at least two drivers of major changes in the HVTS: technology and the changing landscape of generation to more renewables. The technological driver is the introduction of a smart grid, which uses electronic devices to replace the electromechanical devices originally incorporated in the HVTS in the 1950s. New technology includes advanced controls that improve system reliability, robustness, and capacity without the need to add transmission lines (an arduous and expensive process). These changes can increase the carrying capacity of the system by 30 percent or more (NETL 2010).

The addition of renewables (e.g., wind, solar) in the generation mix places stress on the HVTS because of their inherent intermittency. The grid must remain balanced with tight voltage and frequency limits, and the more nondispatchable (intermittent) generation feeding the system, the more difficult the system control and the more reserve generation required to meet demand.

Accelerating the transition to fully deployed smart grid technology will enhance control of the HVTS as power flow demands increase between regions. But, as discussed below, there is a tradeoff between smart control systems, which require the increased use of internet-connected devices, and the potential for cyberattack (NIST 2014).

Distribution System

The last segment of the electricity supply system is the distribution system (DS), which takes the electricity off the HVTS using step-down transformers and distributes it to the consumer, such as a residence or a commercial or industrial facility. This segment accounts for about 35 percent of the overall system costs; US investment in the distribution system since 2000 totals over $400 billion (EEI 2017). It is also the most complicated—most outages result from problems in the distribution system.

There are neither standards for DS reliability (-Warwick et al. 2016) nor federal agency oversight of the system (as provided by FERC for the HVTS). State regulators for the IOUs and the managing boards for the public utilities have regulatory responsibility for distribution; DS operation, maintenance, and planning are the responsibility of the local utility.

Traditionally, the DS is located aboveground. There are over 5.5 million miles of distribution lines in the -United States and over 180 million power poles (-Warwick et al. 2016). The undergrounding of electricity distribution began in major cities in the late 19th century and then spread to some suburban regions of large cities. Putting the DS underground has many advantages, such as improved aesthetics and greater resistance to wind, fire, and ice damage. But there are disadvantages as well, such as greater flooding risk, higher costs, and more disruptive maintenance (Sharma 2017).

The “reintroduction” of electric vehicles[4] in the -United States may affect the distribution system of the future (Bullis 2013). Currently, less than 1 percent of electricity is used for transportation (EIA 2018), but with the development of modern electric cars and incentives to deploy them, the demand for electricity (especially in the evening) may increase substantially. There is plenty of generation and transmission capacity to meet this demand, but the increased charging requirements may challenge the distribution system, depending on when and where vehicle batteries are charged (Bullis 2013).

Microgrids are distributed generation and storage resources in the DS that can be cooperatively managed to form separate, “islanded” small grids in the event of a disturbance on the larger integrated grid (Warwick et al. 2016). The management of distributed generation and microgrids requires a high degree of automation. In particular, photovoltaic systems and electric vehicles connected to the DS require the ability to manage bi-directional power flow on a real-time basis. But while DS automation will improve the reliability and resilience of the system, it will also increase the number of entry points for potential cyberattacks (NIST 2014).

To improve DS reliability and resilience, utilities are implementing a suite of measures, including distribution automation, real-time fault analysis, and outage management systems. In addition, real-time pricing of electricity will contribute to the levelling of peak electricity demand, reducing the need for additional generation. But substantial investment—as much as $5 trillion—is required to transition to full automation (Rhodes 2017).

Major Vulnerabilities

Table 4

Historically, natural events, especially severe -weather, are the greatest contributor to loss of system reliability (McLinn 2010). The most recent DOE Office of Electricity annual report on electric disturbances shows that, in 2017, 149 events in the United States met their reporting criteria (DOE 2018), and the cumulative number of customers affected was almost 5.2 million. Severe weather accounted for 51 percent of the events, but affected 92.4 percent of the customers. Physical attacks and vandalism represented about 23 percent of the events but affected only about 0.5 percent of customers.

Electric System Resilience, Risk Assessment, and Management

Resilience is different from reliability, which is the ability of the system to deliver electricity to the customer in the quantity and quality demanded (Clark-Ginsberg 2016). The National Infrastructure Advisory Council defines four dimensions of resilience (Berkeley and Wallace 2010):

• Robustness: the ability to absorb shocks and continue operating
• Resourcefulness: the ability to manage a crisis during its evolution
• Rapid recovery: the ability to return service as quickly as possible
• Adaptability: the ability to improve system resilience based on lessons learned from past incidents or near misses.

The risks can be managed with future grid designs that maximize flexibility of grid operation. Management measures include hardening of the components to increase resistance to winds, winter storms, and flooding; and system modernization with improved sensors, automated controls, information management, and analytic tools (DOE 2017b). Proper preparation for such events reduces the risks, including effective equipment lifecycle management programs, vegetation management, and warehousing of critical equipment. Increased cybersecurity measures are appropriate to deal with increasing cyberattack threats; such measures are discussed thoroughly in Cyber Threat and Vulnerability Analysis of the US Electricity Sector (Glenn et al. 2016).

Conclusions

• The reliable and resilient operation of the electric system is critical for the health and safety of the -public and the health of the US economy and -security.
• The capital stock turnover for the electric system is slow, measured in decades, whereas the technologies needed to strengthen the system advance in months, creating potential challenges for long-term planning.
• The entire electric system is in the “late-in-life” stage, but still maintains a very high level of reliability.
• Trillions of dollars of investment are required to rebuild the infrastructure of the US electric system.
• Climate change poses a significant threat to the reliability and resilience of the electric system by increasing the frequency and severity of weather-related threats.
• The use of “smart” devices in the electric system improves its reliability and resilience, but also increases its vulnerability to cyberattacks.

Next Steps

• Full deployment of the smart grid concept for the HVTS and the diverse distribution systems across the country must become a top priority. Sufficient funds need to be allocated at the federal, state, and local levels to maintain the reliability and resilience of the US electric system in light of increased stresses from the effects of climate change and growing deployment of renewable generation and electric vehicles. In addition to government support, the ratepayers and stakeholders of US utilities must contribute to this transition through cost recovery mechanisms, such as rate increases, appropriate to the type of utility involved.
• The automation of the US electric system is necessary, but appropriate care must be exercised to minimize the potential effects of cyberattacks from all sources.
• Greater funding and increased focus for the research, development, and deployment of practical electric storage devices at the utility scale are required.

Acknowledgment

Cameron Fletcher did a fantastic job of editing my article.

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