Building a national super grid in America

Building a national super grid in America

[ By Alice Friedemann  author of “When Trucks Stop Running: Energy and the Future of Transportation, 2015, Springer]

A national supergrid is seen as essential for integrating renewable power into the electric grid. It is not clear if penetration of renewables beyond 33 or 50% is possible if this isn’t done, since many regions of the US have limited renewable power options and a very large grid is needed to keep it in balance, since the wind isn’t blowing (especially not in the entire Southeast year-round) and the sun isn’t shining everywhere, nor do vast regions have hydropower, geothermal, and other renewable power.

Renewables are not evenly distributed. Most of the wind is in the Midwest and offshore, nearly all of the geothermal and concentrated solar power is in the Southwest.

Just as many natural gas and oil deposits are stranded and unexploited because the cost to build pipelines to them is too high, many renewable resources are unable to generate enough power to justify building transmission lines to them, especially when they’re also far from cities.

The estimated cost of adding a national transmission grid varies a great deal, but several come to around $1 trillion dollars (i.e. Chupka 2008 $880 billion).

If America tried to balance intermittent power over a wide area like Denmark and construct a national grid, there is the potential for a national blackout.

Although large regions can increase stability, this isn’t always true, since operators can’t see adjoining systems well enough to detect impending extreme events and take countermeasures quickly (CEC).

Size doesn’t always increase reliability because it provides multiple paths for local disturbances to propagate, which can lead to complex chains of cascading failures (Morgan).

In addition, a lack of investment and increased loading of lines and transformers without increased transmission capacity (Clark) and poorly planned generation and transmission capacity (Blumsack) has led to the potential for a widespread blackout. Additional blackout riisks are cyber-attack, terrorism, and aging equipment (NAS 2012).

Because the system is a network, reducing congestion in one part of the system may shift it to another (the next-most-vulnerable) part. Congestion also tends to move around the system from year to year and in response to weather and other seasonal factors. In addition, solving the problem of transmission constraints within the United States will also require cooperation with Canada. Many scheduled power transactions within the U.S., particularly east-to-west transactions within the Eastern Interconnection, flow over transmission lines located in Canada before reaching loads in the U.S. This is a particular problem at points in the upper Midwest where the transmission systems of the two countries interconnect. These unintended flows (or “loop flows”) often require transmission service curtailments in the U.S. The benefit of increasing transmission (USDOE 2002).

An American supergrid would need at least 50,000 miles of new lines, with multiple underground links from the Great Plains to the coasts each more than 1,000 or even 1,500 miles long, and capacities for each of these miles would have to be in the multiples of gigawatts, not a few hundred megawatts. The whole project would require considerable and rapid scaling up of the existing system. to think that these megaprojects could be designed, the designs approved, and the necessary rights of way obtained in a few years is to have an entirely unrealistic understanding of America’s engineering capabilities, its multiple regulatory bureaucracies, and its extraordinary NIMBYism and litigiousness (Smil).

Source: Vaclav Smil

Source: Vaclav Smil


Bureaucratic challenges (USDOE)

It can take as long as 14 years to get permission to add transmission lines. For example, it took the American Electric Power Company fourteen years to obtain siting approval for a 90-mile 765 kV transmission project, while it required only two to construct it.

Ten years after it was first proposed, a major transmission project by American Electric Power (AEP) in West Virginia and Virginia is still about a year from final approval. The following chronology documents the delays resulting from state regulators’ efforts to take account of local and other concerns, and from lack of coordination among the principal parties. 1991—AEP submits a proposal for a 765-kV transmission line to Virginia, West Virginia, the U.S. Forest Service, the National Park Service, and the U.S. Army Corps of Engineers with the goals of maintaining reliability in southern West Virginia and southwestern Virginia and reducing the risks of a cascading outage that could affect many states in the eastern U.S.

  • 1992–1994—Extensive hearings are held in Virginia and West Virginia, many in potentially affected localities.
  • 1996—The Forest Service issues a draft environmental impact statement which recommends that the line not be constructed as proposed because it will cross sensitive public lands.
  • 1997— AEP proposes, to the regulatory commissions in the two states, a longer alternate route that would cross less sensitive areas than the initial route.
  • 1998—The West Virginia Public Service Commission approves its portion of the alternate route. Later in 1998—AEP agrees to a request from the Virginia Corporation Commission that the utility conduct a detailed study of a second alternate route. After AEP completes its review, it agrees that the second route is acceptable although this route would not allow as much margin for future load growth as had been available with the first alternate route.
  • 2001—The Virginia Corporation Commission approves the second route, chiefly because this route would have fewer adverse environmental and social impacts than the previous routes.
  • Late 2001—The West Virginia Public Service Commission must review and approve the newest route even though the West Virginia portion of that route differs very little from the one the commission approved in June 1998. In addition, because the newest route would also cross about 11 miles of national forest in an area not studied in the Forest Service’s 1996 draft environmental impact statement, the Forest Service must conduct a supplementary analysis before deciding whether to grant a permit for construction.

Sierra Pacific’s experience in building a 163-mile transmission line is an example of the costs and delays that can arise when transmission projects involve multiple federal agencies with land management responsibilities.

  • Sierra Pacific prepared detailed plans for the Alturas project in 1992.
  • The Nevada Public Service Commission approved the project in November 1993.
  • After obtaining Nevada’s approval, Sierra Pacific turned to the other affected agencies—the California Public Utilities Commission (CPUC) and several Federal agencies: the U.S. Bureau of Land Management (BLM), the U.S. Forest Service, BPA, and the U.S. Fish and Wildlife Service. BLM had the most acreage affected by the proposal and became the lead agency for the Federal review of the project.
  • CPUC became the lead agency for state environmental purposes. In spring 1994, BLM and CPUC collaborated to begin a draft environmental impact report (EIR) for the state and a draft environmental impact statement (EIS) for the Federal agencies. Sierra Pacific paid the cost of the studies.
  • BLM issued the final EIS in November 1995 and approved its portion of the project in February 1996.
  • The CPUC approved its portion of the line in January of 1996.
  • In February 1996, the manager of the Toiyabe National Forest issued a “no action” decision, arguing that the EIS was flawed because it had not addressed a sufficiently wide range of alternatives.
  • Eventually, Sierra Pacific decided to pursue an alternative route and withdrew the application to cross the Toiyabe area. In April 1997, the Modoc National Forest manager denied the project a permit to cross a three-mile portion of the Modoc National Forest.
  • The applicant appealed this decision to the chief of the Forest Service in May 1997; a permit was issued October 1997.
  • However, several other parties to the proceeding appealed this permit. After review, the decision to issue the permit was upheld in January 1998.
  • Construction was begun in February 1998 and completed in December 1998. Sierra Pacific estimates that the project was delayed by at least two years and that these delays led to additional costs of more than $20 million.

Underground cables transmit power with very low electromagnetic fields in areas where overhead lines are impractical or unpopular. Costs are 5 to 10 times that of overhead lines, and electrical characteristics limit AC lines to about 25 miles.

Higher voltage lines can carry more power than lower voltage lines. The highest transmission voltage line in North America is 765 kV. Higher voltages are possible, but require much larger right-of-ways, increase need for reactive power reserves, and generate stronger electromagnetic fields. HVDC provides an economic and controllable alternative to AC for long distance power transmission. DC can also be used to link asynchronous systems and for long distance transmission under ground/water. Conversion costs from AC to DC and then back to AC have limited usage. Currently there are several thousand miles of HVDC in North America.


Clearly it is unlikely that a national grid will ever be built due to the risks of a national blackout, the already too expensive need to upgrade the existing grid, the NIMBY litigious process of approval and reluctance of states to allow power generated in their state across borders, and capital costs are going to prevent shared solar and wind across the nation.

Because it is unlikely we can scale up wind and solar due to intermittency and seasonal issues, and so much power is lost across long transmission distances, and the grid so vulnerable to terrorism, it may not make sense to have a national grid anyhow.  It would be better to spend the energy required on insulating homes, energy efficient appliances and vehicles, and other efforts to prepare for the decline of fossil fuels and consequently electricity as well.


Blumsack, S.A. 2006. Network topologies and transmission investment under electric-industry restructuring. Carnegie Mellon University.

CEC. 2008. Transmission technology research for renewable integration. California Energy Commission. CEC-500-2014-059

Chupka, M.W. et al. November 2008. Transforming America’s Power Industry: The Investment Challenge 2010-2030. The Brattle Group.

Clark, H.K. 2004. It’s Time to Challenge Conventional Wisdom. Transmission & Distribution World.

Morgan, M., et al. 2011. Extreme Events. California Energy Commission. CEC-500- 2013-031.

NAS. 2012. Terrorism and the electric power delivery system. National Academy of Sciences.

Smil, V. 2010. Energy myths and realities. AIE Press.

USDOE. May 2002. National transmission grid study. United States Department of Energy.

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