The world's largest machine needs an upgrade — and it's costing consumers big money.
America's 7 million miles of transmission and distribution system wires, often called the planet's biggest networked machine, have an estimated value as high as $2 trillion. Built up over a century, the network supports the world's largest economy, but there are mounting worries it is not keeping up with the times.
Pushed by public policy and favorable economics, U.S. utilities are adding more renewable energy and distributed resources to their systems, increasing the complexity of a system once run by fewer centralized generators. At the same time, a number of states are stepping up efforts to electrify other sectors of the economy, potentially creating a huge source of controllable electric load for utilities through resources like electric vehicles.
Better digital monitoring and control systems for the transmission system could help it adapt to these changes, according to a new industry white paper.
Today, upgraded data communication, analysis and control systems could allow the transmission system to save customers an estimated $2 billion per year, according to “Bringing the Grid to Life," a new paper from the Working for Advanced Transmission Technologies (WATT) Coalition, a group of advanced transmission vendors.
Separating consumers from those savings is what's known in regulatory circles as the "perverse incentive," the trade group argues. Utilities make higher revenues from building new lines — a lengthy and costly process — but much less from optimizing the existing system with new technologies.
This, according to WATT and other advocates, limits utility investments and directs them away from the innovation their systems need to move to a power system with higher levels of renewable resources.
The Federal Energy Regulatory Commission (FERC) can fix the perverse incentive, former Chairman James Hoecker told Utility Dive. But to do that, FERC must look closely “at what advanced transmission system technologies can offer and at what the purpose of the transmission system really is.”
Congestion and advanced technologies
The U.S. power system is listed as the number one greatest engineering achievement of the 20th century by the National Academy of Engineering. But this is the 21st century and there are “proven, advanced technologies” that add reliability and resilience, WATT argues. They allow system operators to identify and use “hidden transmission capacity” or to use lines more efficiently.
Those capabilities are becoming increasingly important as transmission congestion rises, WATT argues. Congestion happens when a system operator sees a set of lines carrying its full capacity. The cost to customers rises because the operator is forced to dispatch electricity from a different location, which is likely to be more expensive than the market's first choice.
In the U.S., congestion decreased between 2009 and 2015 because of major transmission capacity expansions, especially those by the Electric Reliability Council of Texas (ERCOT), the Midcontinent Independent System Operator (MISO), and the Southwest Power Pool (SPP), according to Rob Gramlich, WATT executive director and author of the white paper.
Looking ahead, less transmission development is planned, aging lines will soon be retired, and utility-scale renewables installed at remote locations will take up more system capacity, Gramlich said. The result will likely be rising congestion nationally, estimated to cost electricity customers $6 billion dollars per year.
A set of three advanced technologies could reduce that cost by $2 billion, WATT argues. Yet expenditures for advanced technologies made up only an estimated 2% to 4% of total spending on the U.S. transmission system between 2014 and 2017, according to a Brattle Group study.
Advanced Power Flow Control
One of the advanced technologies is Advanced Power Flow Control (APFC), which “pushes or pulls power away from overloaded lines,” according to Todd Ryan, Director of Regulatory Affairs for AFPC provider Smart Wires.
APFC devices on lines “choose which line should carry the power,” Ryan told Utility Dive. If one of a set of APFC-equipped lines is lost, “the power can still flow on the rest of the set of lines.”
The equipment — often installed on transmission lines themselves — can “be quickly deployed, easily scaled to meet the size of the need, or redeployed to new parts of the grid when no longer needed in the current location,” the WATT paper adds.
A 2016 Pacific Gas and Electric (PG&E) pilot project demonstrated AFPC “can reduce line flow and phase imbalance while maintaining high availability and reliability and minimizing impact to primary protection communications,” PG&E reported. It showed scale deployment would be “significantly less costly than a traditional transmission upgrade to increase capacity in most scenarios.” A Minnesota Power pilot project is ongoing.
Dynamic Line Rating
The second advanced technology identified by WATT is Dynamic Line Rating (DLR), which incorporates monitoring devices that read, or rate, a line’s actual capacity.
In the absence of DLR real time ratings, system operators assume there is congestion necessitating redispatch when capacity reaches the line’s “set fixed limit,” WATT reports.
Hudson Gilmer, VP of Power Markets for DLR provider Genscape, said “95% to 98% of the time” the ambient conditions of affecting the line are better than assumed and significant actual capacity is still available.
“A utility gets two main benefits, Gilmer told Utility Dive. “One is increased available capacity on the line.” The other is monitoring that reveals the wire’s condition. “It’s almost absurd that a smart refrigerator has more monitoring that a hundred-million-dollar transmission line.”
SPP is running field tests of DLR now, according to Jay Caspary, director of research and development at the grid operator. The results of a PJM pilot are not yet public, but PJM engineer Shaun Murphy told Utility Dive the it showed “the technology produced an overall reduction in congestion.”
Gilmer said the cost of deploying DLR is “generally 1% or less” of the cost of line replacement. Even where monitoring reveals the lines need to be replaced, the cost of the deployment is likely to be less than the cost of an outage, he acknowledged.
Inaccurately rated lines challenge renewables in three ways, Gilmer said. First, projects are less cost-effective if perceived congestion forces system operators to curtail output. Second, markets interpret the congestion as oversupply, lowering returns. And, third, a new line may be required to interconnect a new project when actual existing capacity is adequate to deliver the generation.
Topology Optimization
The third advanced technology is Topology Optimization, in which software automatically reconfigures power flow around congestion.
“The reconfigurations are implemented through switching on/off existing high voltage circuit breakers,” WATT reports. Topology optimization distributes the power flow more evenly over the system to increase the capacity the grid can move.
Caspary said SPP is running simulations of “stressful scenarios” and using the data derived from topology optimization software “to help us understand the stress on the system.”
Pilots will follow if analysis of the simulations verifies that the technology “does what it is designed to do,” Caspary said. “These are big changes to how we have traditionally operated the system and we have to be conservative about them.”
Risk vs. value
The caution in deploying advanced technologies is because there is risk as well as value, SPP Vice President for Engineering Lanny Nickell told Utility Dive.
“The risk is allowing more aggressive system operations and the theoretical value is allowing a higher degree of system use," he said.
WATT’s Gramlich, who is also president of transmission consultant Grid Strategies, said the three advanced technologies have two common challenges. One is that the misalignment of utility incentives favors big capital expenditures that earn big returns while these options cost significantly less. The other is that they have not yet found a place in transmission planning processes.
Smart Wires’ Ryan echoed concerns about utility incentives.
To innovate, a company has to commit significant workforce hours and take on risk, he said. Typically, utilities are rewarded for that commitment by building assets and earning a rate of return, but they cannot get the same reward for improving operations on their existing systems,
“In transmission, there are none of those ingredients," he said.
Utilities face “more processes with fewer people all the time” Ryan added. And they protect their reliability with almost “zero risk tolerance.” Due to the perverse incentive, deployment of advanced technologies would cost them the higher returns they might earn from building new lines.
“The point is that utilities’ slowness to adopt these advanced technologies is not because they are trying to maximize profits or gold plate their systems,” Ryan said. “It is because none of the ingredients of innovation are there. WATT wants the incentive structure addressed.”
What FERC can do
SPP’s Nickell said FERC will have the same challenge as utilities — "evaluating the benefits of the technologies against the risk of deploying them.”
The Energy Policy Act of 2005 makes that question relevant for these advanced technologies, according to WATT. It allows FERC to approve higher incentives for expenditures that are part of a grid expansion proposal and have some risk. If FERC decides they are “proven technologies” they would not qualify for the higher incentives, despite their benefits.
WATT lists four ways FERC can support these technologies. One is to invite filings that propose better incentives. The second is to move system operators toward including them in operations and planning. The third is to introduce performance metrics that allow returns for reducing congestion and other costs. Finally, a FERC-led technical conference and staff inquiry could drive utility adoption.
SPP’s Nickell and Caspary agreed the technical conference could drive interest in transmission innovation.
Smart Wires’ Ryan was also enthusiastic about a technical conference as a way to start a conversation about innovation in transmission and about ways to eliminate barriers to innovation. “There are great people in this industry who deserve to not be penalized for the innovation they are leading.”
Genscape’s Gilmer said WATT meetings with FERC commissioners and staffs about these options have been productive. A pending WATT filing would allow interconnection requests to use the new technologies in place of new lines.
FERC declined requests to interview commissioners or staff for this piece.
Former FERC Chair Hoecker, now senior counsel at law firm Husch and Blackwell, said courts have affirmed that the commission has jurisdiction over transmission system planning. FERC itself does not plan, but it sets the “conditions precedent for certain kinds of industry behavior."
“If the commission tells the regional systems to do things a certain way, they would do it," he said.
Adjusting incentives
FERC could begin by formally asking the questions raised by WATT, which would invite the industry to respond with comments, he said. After study of that input, the commission “can announce, based on what the record supports, the incentives it will approve to encourage investment.”
First, however, the commission needs to adjust its perspective on incentives, Hoecker said.
“For years, FERC has looked at incentives in terms of immediate needs,” Hoecker said. “The planning horizon has always been relatively short, which works if you're just trying to keep the lights on today. When you don’t know where you're going, any road will get you there.”
“To reinvent and modernize the grid to prepare it for the stresses it will face in a more electrified economy and electrified future, the commission needs to decide what kind of grid it wants,” Hoecker said.
Advanced digital technologies that make the system more efficient historically have not the primary focus for utilities that depend on keeping their rate bases healthy, the former chairman said. But monitoring and control and situational awareness are much more critical now.
“Things that make the grid more flexible and adaptable and resilient are a big net positive for consumers and for the industry,” Hoecker said. “We need to make these technologies competitive with other kinds of electric system investments and use them in a new kind of planning.”
Different regional systems take their own approaches to transmission modernization, he acknowledged. “But all regions need to be ready to cope with the stresses of a much more dynamic and diverse market and a decentralized and distributed system. It will have an unprecedented number of competing resources at the production end and millions of consumers participating in the market in ways they never have before at the other end.”
Today’s grid is not ready to deal with that kind of power system, Hoecker said.
“To make that happen, the commission has to figure out where it wants to go, not just next year, or in five years, but where the electric economy needs to be in 2030 or 2040. And then it has to decide how to give companies incentives to build that system.”
