Railroads and electric power companies are each an American Prometheus. Like steel, chemicals, transportation, energy, manufacturing and other fossil fuel-reliant American industries, they find themselves in an economic, social, and policy world not of their own making.
Whether labeled decarbonization, restructuring, or modernization, the electrification of North American industry is both a component and a driver of fundamental changes. In addition to a historical love of competitive markets, the growing concern about climate change and extreme weather, alarm about the state of electric grid, the clamor for electric highway vehicles, consumer demand for zero-emissions and zero-fuel renewable resources, and the rise of IT, OT and AI have already made basic changes in what we used to call the “utility” business. It’s inevitable that railroads, the critical link that historically sustained the nation’s supply chains, will be shaped by these developments, too.
That said, no case for electrification of railroad operations, especially heavy freight transportation, can be made without acknowledging both the huge potential cost of this transformation—arguably the biggest since the abandonment of steam—and the cost savings potential that electric motive power could deliver in terms of reduced maintenance, speed and flexibility, reliability, fuel efficiency and environmental benefits. While apprehensions among today’s railroaders about the costs of converting to grid power, biofuels, batteries or a mix thereof (or possibly hydrogen) are understandable, the prospect of rail electrification caused far fewer such concerns among public and private analysts in the 1970s and 1980s. Studies in that era entertained the application of electricity to most freight and passenger operations as a practical propulsion alternative to dieselization.
New sustainability imperatives for business may now be coming into focus for railroads. The time has probably arrived for them to put pen to paper about the cost, timing and complications of getting off fossil fuel because there may be risks associated with not doing so. At a minimum, we can assume that railroad sustainability officers are busy identifying their strategic interests in each step toward rail electrification and decarbonization. In the process, they should understand the changing structure and operation of today’s electric power system, as well as the potential strategic importance of the rail network to an economy driven by electrons instead of BTUs.
This is not your grandfather’s electric system in any case. Its capabilities are being tested by the demands that are made on it by increasingly distributed generation and resources, the onslaught of electric highway vehicles and charging stations, evolving energy storage technologies, electrification of industrial processes, and the need for access to location-constrained renewable energy across the U.S. and North America. The level of infrastructure investment that government or industry assumed was necessary or sufficient to electrify railroads in 1980 may no longer be sufficient. The grid—that is to say, the vast, synchronized machine inherited from the 20th century and comprised of technologies, physical structures and institutions, rules, protocols and policies—is undergoing multiple transformations. A sizeable share of transmission wires and switching equipment is outdated and operating well beyond its useful life in pursuit of operational objectives that no longer pertain. Climate-induced extreme weather has revealed system vulnerabilities and inadequacies. In its latest reliability assessment, even the North American Electric Reliability Corporation asks “Can the Grid Take the Heat?”
Projected growth of electricity demand will only add to the stress. Annual electrical demand is expected to increase by 15%, 600 terrawatt hours (TWh), by 2030; and 85%, 3,700 TWh ,by 2050, effectively doubling today’s national electricity demand of 4,500 TWh. Industrial processes are expected to become more electrified and rely more heavily on decarbonized electric power. Regulators, policymakers and industry leaders already recognize that time is growing short for mastering these challenges. The announced goal of “net-zero” carbon (greenhouse gas) emissions by 2035 is looming. Although policy makers are depending on massive investment in high voltage transmission lines to deliver wind and solar power in quantities sufficient to meet these goals and reduce the climate threat, it remains nearly impossible to plan and build a major transmission line (if starting today) in that intervening time. The denizens of the grid who seek to partner with the whole transportation sector and not just EVs therefore have more work to do.
So, let’s first take a look at what has occurred in the years since the electric utility industry stated that “electrification of main line railroads offers many advantages and should be vigorously pursued” (Edison Electric Institute, A Report [of the Task Force on Railroad Electrification] to the Electrification Committee of EEI, 1970) and the U.S. Department of Transportation reported that “railroad electrification is the only available alternative to diesel-electric operations on high-density, long-haul railroad lines” (Government-Industry Task Force on Railroad Electrification, A Review of Factors Influencing Railroad Electrification, 1974). Over the past 50 years, the domestic power industry changed in the following four ways:
1: Distributed Resources and Competition: The U.S. power market was historically highly centralized. Although the U.S. has nearly 2,000 distribution utilities, mostly owned by municipalities and other government agencies, and more than 800 customer-owned cooperatives, the dominant power producers and distributors have been the 174 investor-owned utilities (IOUs), which have been heavily regulated—primarily by the states —in exchange for state-franchised service territories. They are natural monopolies that have dominated the industry through vertical control of generation, distribution and transmission within a state-authorized service territory.
Since the days of Edison and Insull, capital intensiveness and scale economies have dictated deployment of large central generation units near concentrations of customers. However, depression and war revealed their limitations. Over time, new electric generation, fuels and digital technologies eroded this structure. Beginning in 1978, Congress introduced non-utility electric generation, customer (demand) participation in electricity markets, and the use of gas turbines for electric generation (previously banned). By then, local utilities had extended their market influence through transmission expansion into neighboring states and interconnected with each other to ensure reliability and address emergencies. New domestic sources of natural gas supply (the U.S. had expected to run out in the ‘70s) and delivery began to change power market fundamentals. Gas revolutionized the fuel mix for electricity generation long before renewables became price-competitive, and, pressed by policy makers to open up to competition, let loose some centrifugal forces in the energy industry and its regulation.
In 1996, the FERC (Federal Energy Regulatory Commission), capitalizing on Congress’ refreshed appetite for opening up “essential” facilities, ordered all electric transmission (generally 69 kV and above) to be “open access”—i.e., no source of generation could be denied access to the wires by pricing or practices that are different from those used by transmission-owning utilities. This newly non-discriminatory environment fostered changes ranging from transparent market pricing mechanisms to development of new sources of generation and, ultimately, formation of independent transmission and services companies. Competition among diverse sources of electricity supply (mostly but not entirely generation) made electric transmission a critical link indispensable to all market players and the public’s interest in reliable and affordable power. “De-monopolization” trends led to creation of independent or “merchant” transmission companies whose entrepreneurial mission was to develop new transmission as a separate business, without retail customers or service territories or regulated returns.
The success of these companies today largely depends on the growing need for interregional projects and the hope that RTOs (regional transmission organizations) and regulators will incorporate their projects into regional plans efficiently and equitably. The need for new transmission additions between regions and markets has been expressly acknowledged by the Department of Energy and Congress, which recently granted FERC limited authority to conduct “backstop” siting and permitting processes when states fail to use their historical siting authority to approve transmission lines shown to advance national policy or legitimately serve the public interest.
Takeaway: Planning to keep the lights on locally is still a utility’s first job. But, from the outside, the electricity business at the wholesale or bulk power level seems to be getting more, not less, complex. Yet that market is also more transparent, flexible and competitive, and therefore more important than it was. The distributed nature of energy resources and entities, including market participation by consumers, public entities and non-utility service providers, translates into commercial opportunities that will continue to grow over the next decade or two.
2: Regionalism: The U.S. grid was (and in many ways, remains) a patchwork of service territories and special operational needs and requirements based on the best available energy sources and corporate realities in each region. Moving power across state and market boundaries, although becoming less challenging, remains difficult. The barriers created by uncoordinated systems, policies, standards and resources profoundly affect prices. The cost of power to users or cities only a few miles apart often differ dramatically because of congestion on the wires, absence of real markets, or discriminatory practices.
Federal regulators responded in 1999 by encouraging establishment of RTOs to manage the grid in accordance with the collective needs and interests in each (usually multistate) region. These RTOs administer a set of tariffs, practices, and mechanisms for power and ancillary services across wide areas and systems, in theory leading to real bulk power markets, an equitable sharing of costs, more forward-looking planning for the future, and enhanced reliability. However, because these institutions were the products of compromise, their market plans, governance, and standards seldom conform to one another. Therefore, a “patchwork” still persists at the wholesale power market level and will for the indefinite future. As Texas found out in recent years, extreme weather can impose terrible penalties for enforced isolation from the larger power market. While RTOs do not collectively comprise a national grid or a national market for power, public policy has only recently begun to identify that as an objective.
Takeaway: As individual power markets expand and meld, the greater the need and the opportunity for longer transmission systems and new technology investments with which to operate these systems. That heightens the need for facilities that span regions and tie markets together. Consequently, proponents of a stronger market and an expansive grid will come to recognize the need to find better, established linear rights-of-way for transmission and other electric power operations.
3: Clean Energy and Decarbonization: After years of development and despite the historical price advantages of natural gas, coal and nuclear energy, the cost to produce wind and solar energy has dropped markedly. The idea of zero-fuel and bio-based energy is transformative. Renewable electric generation has gone from 1% of the U.S. power supply to 10% today. Hundreds of renewables projects are being proposed for grid interconnection, overwhelming the bureaucratic mechanisms of the RTOs. As of 2022, nearly 800 GW (gigawatts) of potential gas and “intermittent” renewable generation and storage facilities were stuck in queues seeking interconnection to the regional grids, while endless studies about the engineering impacts of adding new resources to the system were pending. Nevertheless, any hope for limiting global warming to 1.5 degrees Celsius by 2050 will depend on the growth in use of renewable resources and biofuels and a reduction in fossil fuel use, which in turn requires a massive expansion and upgrade of the electric transmission grid.
Easy to say! Transmission investment grew only 2% annually in recent years due to shifting policy priorities, NIMBY concerns, and a tangle of knotty permitting and cost allocation debates. The divide between state and federal regulators that share electricity industry oversight responsibility on behalf of utilities, consumers and the environment has fueled ongoing uncertainties. States, whose scope of interest may be limited or parochial, and the FERC have left unresolved many questions about how to improve long-term transmission planning and generator interconnection.
Consequently, new transmission projects have been entangled in complex permitting processes under state siting and permitting laws and an array of federal restrictions under NEPA, the Clean Water Act and the numerous uncoordinated laws designed to protect important resources. It is therefore remarkable when a developer can design, get approved and construct a transmission line in less than a decade. If a project were to cross more than one state or market, that time could routinely double. Because of such dysfunction and frustration about access to renewable resources, think tanks and planners have often warmed to the idea of a “macrogrid” or “supergrid” that would bridge all regional and local markets, thereby enabling RTOs or others to move large amounts of power greater than 500kV anywhere as needed, to keep the lights are on even under the most adverse conditions.
As a potential location for adding new facilities to the transmission grid, only pipeline routes and the nation’s highways come close to providing the extensive linear rights-of-way that match the network of private property rights-of-way owned by railroads. In addition to retrofitting aging switching locomotives, rail yards may be ideal hosts for wind or solar facilities or charging stations, or installing mobile energy storage (batteries) on rails to augment the railroad’s own needs or to send power back to the grid to support system reliability and resilience.
Takeaway: Electrification is no longer easily justified without low- or no-carbon fuel. Producing and delivering renewables at scale remains a challenge in most parts of the country. Building transmission is an arduous, expensive, time-consuming process, although policymakers have noticed that its most difficult aspect—permitting and siting new facilities—needs to be addressed. Utilization of established transportation rights-of-way is a key solution that would minimize the ecological and legal impacts inherent in new development and thereby help relieve the regulatory drag on grid expansion.
4: Technology and Markets: When rail electrification was last taken seriously a half century ago, the vast electro-mechanical grid had yet to be digitized. The Internet and electric power technologies have since fostered business models that are nimble and more productive, markets that are faster and more transparent, forecasting that is better, and retail and wholesale transactions that can respond to changes in demand and promote energy efficiency in real time. At the distribution level, new devices and meters have heralded the emergence of the “Smart Grid.” Sensor-based systems help planners make long-term planning decisions and provide operators with situational awareness on the grid in real time—a significant contribution in an era of extreme weather and complex, decentralized, bilateral energy transactions. Purchased power agreements and/or capacity market auctions allow power suppliers to provide energy from multiple kinds of resources—generators, demand response, energy efficiency practices, and even transmission upgrades—when needed. Competitive markets help lower energy costs, but usually fail to price-in externalities like carbon and therefore may not yet favor renewables in many cases.
The most powerful advances in technology have come in wind and solar generation and energy storage technologies, including batteries that make renewables more reliable and automobiles faster and cleaner. A majority of states have adopted renewable portfolio standards to ensure their utilities actively purchase cleaner resources (many have not). Yet some regional collaborations have helped integrate the grid and manage the uncertainties that transformational trends produce. Since the domestic electric industry is dominated by private institutions that must keep an eye on their returns, the value of their assets and their often-huge need for capital, they share railroads’ concerns in important ways.
Takeaway: Leadership in this environment isn’t for the faint of heart. Change in the coming decade will be breathtaking, with much of it driven by electrification and escalating climate worries. The role of new technologies in managing the grid, ensuring reliable service and (hopefully) restraining prices cannot be underestimated. Sustainability—for railroads and other industries —will involve more than innovative ESG reporting. It will entail keeping pace with change.
Collaboration between the rail and power businesses and among their regulators is important for many reasons. Public-private partnerships will multiply in the transportation and energy spaces. Moreover, other freight and passenger carriers will be switching to electric (mainly renewable) power, partly at taxpayers’ expense and potentially impacting the costs and speed of intermodal transportation. If electrification is some part of the future of railroad operations, railroaders will find the power business more exciting, diverse, and more driven to compete than it once was. It may also become a more entrepreneurial and less expensive place to operate.
Currently, the upfront costs of electrification may be disguising a revenue-enhancing opportunity. The need for new and upgraded transmission facilities, especially those that portend an integrated and decarbonized national grid, represents an opportunity to supply highly valued railroad rights-of-way as sites for high-voltage transmission, particularly (but not solely) high-voltage DC lines that would have minimal adverse impact on railroad operations. But this opportunity will not last indefinitely. Uncharacteristically, grid designers may decide to overbuild in anticipation of future needs. Even if more reliable and economic in the long run, projects that are too venturesome may run afoul of regulatory prudence standards and cost-of-service restrictions. Consequently, many interregional projects, including investments in catenary, batteries or hydrogen generation, may come from merchant transmission developers and technology companies supported by private equity and taxpayers as much as the vertical utilities that might otherwise supply the power for electrification. Long story short, rail electrification won’t be as simple as “Where do I plug in?”
In any event, the tradition among railroads and IOUs is to own and manage their Promethean businesses as private (regulated) enterprises. I see no reason that should not continue, despite the central importance of electricity and transportation to the economy and the public interest. Yet, it is also true that this business model will have to demonstrate its real adaptability. There are several possible future scenarios, degrees of electrification, and structural variables, all of which will have different cost profiles and implications for the consuming public. Policymakers, government, and all elements of the electricity industry have been immersed for three decades in studying how the future power system and infrastructure is likely to evolve. That conversation has yielded many new ideas and developments. Railroaders are invited to tune in.
Jim Hoecker, J.D., Ph.D, is Counsel to the Rail Electrification Council and former Chairman, Federal Energy Regulatory Commission. The views in this article are his.
For additional insight, listen to the two-part Rail Group On Air podcast with the Rail Electrification Council: