Transmission: The unsung hero of the DOE grid reliability study RSS Feed

Transmission: The unsung hero of the DOE grid reliability study

Much of the media scrutiny on the Department of Energy grid reliability study focused on its treatment of generation resources, but just as important to ensuring clean and reliable electricity supply is the grid that connects them.

Annual spending on U.S. transmission is expected to peak at $22.5 billion in 2017 before declining, according to a recent Edison Electric Institute (EEI) review of projects. But increasingly, sector insiders are concerned that may not be enough to meet the needs of a changing power system.

“We spend a lot of time looking at the merits of individual projects but we also need to integrate the grid as a whole,” said James Hoecker, former chairman of the Federal Energy Regulatory Commission (FERC). “An integrated system can meet the needs and manage the changes that are out there waiting but are hard to predict.”

The DOE study also acknowledged the need for “major transmission additions to connect the remote generation to the rest of the grid and to load centers.” It recommends a review of “regulatory burdens for siting and permitting” of generation and transmission infrastructure and “actions to accelerate the process and reduce costs.”

For transmission developers, the review cannot come fast enough. Jon Jipping, COO of leading transmission developer ITC Holdings, said system planners often fail to see the urgency of rebuilding the electricity delivery system.

“We are demanding that our infrastructure do things it was not designed to do,” Jipping said. “Never has both the need for reliability and the change in energy generation been so great. Transmission is central to both.”

Transmission needs and costs

Annual investment in U.S. transmission was $20.1 billion in 2015 and $21.5 billion last year, according to EEI. The utility trade group projects $22.5 billion in spending this year and cataloged “over 150 projects totaling approximately $41 billion in transmission investments through 2019.”

More investment could come due to “continued retirements of traditional baseload coal-fueled and nuclear power plants and a greater reliance on new natural gas-fueled plants,” the EEI review reports. A more “robust and flexible” system will be needed “to accommodate drastic changes in flows and dispatch” from variable renewables and to integrate plug-in electric vehicle and battery technologies.

Over 24,000 miles of new transmission was built from 2012 to 2017 at a cost of $102 billion, the DOE study reported. Well-planned transmission is “critical” to reducing costly system congestion and easing local over-generation issues.

But not all transmission investments are good ones, DOE cautions. Some spending can “increase customers’ retail bills to the extent that they are not offset by savings attributable to access to lower-cost generation or reduced congestion costs.”

System operators and transmission builders face “time-consuming, involved, and complex” challenges in developing or upgrading lines, DOE reported. First, a rigorous planning process must demonstrate the need. Then, costs must be equitably allocated and state and federal regulators must approve the line’s siting and permit its construction.

The whole process can often take over a decade as developers contend with landowner opposition, court challenges and environmental concerns.

Rocky Mountain Power (RMP) spokesperson David Eskelsen said his company contended with any of those issues in the ten-year development of its Energy Gateway transmission project, still ongoing.

The first challenge was “the complexity of the permitting process,” Eskelsen wrote in an email. The second was “the acquisition of private rights-of-way once federal land-use approvals are received.”

Even with those difficulties, a number of transmission developers in the nation’s organized power markets have found business in recent years building out new lines to serve the expansion of renewable energy. But that success in individual markets has been difficult to replicate across regions, leaving some to conclude additional policy guidance is needed to allow new lines to be strung.

Read full article at Utility Dive