By Christen Smith, Tom Kleckner and Michael Kuser

Representatives from utilities, RTOs, technology vendors and researchers gathered at FERC headquarters in D.C. last week for a staff-led workshop to discuss the role of grid-enhancing technologies (GETs) in transmission planning and operations and explore how FERC can help the industry address challenges related to their deployment (AD19-19).

GETs include power-flow control and transmission-switching equipment, storage, and advanced line rating technologies. Commissioner Richard Glick — the only commissioner in attendance — said he was struck by evidence that 20 to 50% of transmission capacity is going unused. He asked panelists the central question of the workshop: why “utilities haven’t adopted these tools, purchasing the hardware or software or deploying software, to improve power flow controls and manual configuration. Why haven’t we done more given the lack of use of the existing grid?”

It’s a “chicken and egg” problem that Washington State University professor Anjan Bose says FERC holds the power to fix, citing how the Department of Energy’s investment in phasor measurement units (PMUs) encouraged widespread use of the technology.

“FERC has to encourage some of these solutions” he said. “Some of the needs have to do with reliability and security and not just decreasing congestion at this one point. That’s something FERC can do. If it is needed for the reliability of the system, FERC has the ability to require it.”

“One of the challenges we have is getting detailed models because vendors don’t provide it because it’s proprietary,” said Robert Bradish, vice president of transmission planning and engineering for American Electric Power. He explained that equipment failures force the utility to send the unit back to the manufacturer for repairs, rather than completing them itself. He said FERC should give operators access to this information, “so we can get insight into the actual workings of technology.”

“Given our responsibility for keeping the lights on, we believe it’s prudent for us to have a conservative risk posture when deploying new technology,” he said. “Once you get a technology that’s out there; that’s proven; that’s got performance metrics around it; that’s got cost benefits around it, then you can get deep into analysis and consideration of it.”

GETs — like transmission line monitoring — could help system operators keep track of damaged or aging infrastructure instead of relying on annual foot patrols, LineVision CEO Hudson Gilmer said.

“I want to touch on the safety benefits of these technologies and transmission line monitoring in particular,” he said. “I’m sure everyone is aware of recent events in the wildfires and the power shutoffs that we would argue largely occurred because of unmonitored power lines.” (See PG&E Stock Plummets amid Wildfires, Shutoffs.)

Gilmer said technologies like the kind his company manufactures gives operators the ability to continuously monitor transmission lines and detect anomalies caused by age, clearance violations, blowouts and icing, among others, and “ultimately improve the safety and reliability of the grid.”

The societal benefits of GETs tend to outweigh the financial benefits, Bose said.

“Most of the cost justifications that are being used today to put in these technologies are on the basis of transmission, the cost of market utilization and so on,” he said. “The major advantages mentioned — reliability, flexibility, security — there are no cost benefits of that to stakeholders. There’s a lot of cost benefit to society, which is why we want this.”

TO Incentives

Some panelists at the conference said sweetening the deal will ease transmission owners’ hesitance to adopt GETs.

“A large monopoly entity makes most of its money investing big dollar capital into projects,” said Rob Gramlich, founder and president of Grid Strategies. “If it’s between that and an alternative, they will always choose that.”

Gramlich, on behalf of the Working for Advanced Transmission Technologies (WATT) Coalition, proposed a program that would allow utilities to reap 25% of the shared savings to load from GET projects valued at less than $25 million that “provide quantifiable congestion-reduction benefits.”

Unlike resilience, reliability or safety, Gramlich said congestion can be measured and monetized. He said deployment incentives worked to increase wind and solar penetration, so it can naturally extend to GETs too.

“I think we’ve heard pretty resoundingly from the RTOs and transmission owners … [that] the RTOs aren’t going to tell the transmission owners what technology to put on their wires at any time,” he said. “I think we’ve crossed out all of the alternatives except incentives.”

Bradish said his company could accept the framework of the coalition’s proposal, but he cautioned against “picking winners and losers” when it comes to chosen technologies.

“I think this incentives concept is beneficial to moving the ball forward,” he said. “There needs to be some criteria around that definition so you don’t lock out certain types of technology and innovation.”

Michael Kormos, Exelon’s senior vice president of wholesale markets and energy policy, argued that while the coalition’s proposal focuses on the right metrics, it would “fall apart very quickly” in PJM’s competitive model.

“We may yearn for the days of more collaborative planning, but that is not what we have created,” he said. “It’s winner-take-all. It’s not just a matter of it’s OK if [the proposal] doesn’t hurt me — I don’t want my competitor to have it at all.”

Former FERC Chair Jon Wellinghoff, CEO of GridPolicy Consulting, proposed a program that allowed participants to vie for shared savings worth up to 50% of the congestion benefit realized. He said this approach moves utilities toward a more market-based solution.

“If we structure it as a competitive process, I think that takes it out of the realm of the TOs deciding,” he said. “It can be decided ultimately by the RTO or planning entity, and ultimately, anyone can come in with the best solution.”

Except, not all TOs like the specificity of either proposal.

“I get nervous when I hear very proscriptive things,” said Robert McKee, director of strategic projects at American Transmission Co. and representative of MISO’s TO sector. “‘It’s got to be under $25 million. It’s got to be this [grid-enhancing] technology.’ By proscribing that, you may be obviating a solution. Rather than proscribing what these projects should be, allow the entity to come in and propose something.”

Steve Leovy, of the Transmission Access Policy Study Group, disagreed that the WATT proposal “is the right solution” or that TO incentives will improve deployment at all.

“It doesn’t sound to me that the lack of incentives is the reason this technology isn’t being adopted,” he said. “I’ve heard a lot more about needing more confidence in new technologies. … Utilities didn’t need special incentive to get rid of copper conductors and start installing aluminum conductors. Technology changes and expectations and best practices should change along with technology. Putting incentives into this mix risks rewarding late adopters.”

Cost-sharing a Nonstarter?

Joe Bowring, president of Monitoring Analytics, PJM’s Independent Market Monitor, said transmission incentives such as cost-sharing programs are inherently flawed and “counterfactual.”

“The idea that you can provide an adequate incentive to a transmission owner to build a project that is 1/1000 the cost of a big transmission line is a nonstarter,” he said. “You cannot overcome that basic return on investment by offering TOs incentives for building cheaper alternatives.”

Bowring said using congestion as a metric fails to recognize that reducing it “is not always better.” Further, the variability of the bulk power system will lead to unreliable forecasting.

“You cannot forecast benefits,” he said. “The numbers are ultimately made up and the results are a variety of subjective assumptions. Cost-benefit analysis might be a good screening tool … but the idea that it’s an appropriate way to incent new technology is not correct.”

David Patton — president of Potomac Economics, the IMM for MISO, ERCOT, NYISO and ISO-NE — agreed, saying that “the problem runs so deep with transmission owners that proposing some marginal incentive for GETs in some cases may work and, in many cases, won’t.”

“My biggest problem with it is, for the most economic GETs, it way under-incents the investments in those technologies,” he said. “You’re not going to be able to correct the incentive problem with the TOs.”

Even if RTOs and ISOs moved forward with the coalition’s proposal and provided the cost-benefit analysis for these GET projects, none of them believed the data would provide enough reliable information on which to base rates.

“The long-term responsibility for that being a valid number for a very specific forecast with a very specific set of outcomes … we would have trouble defending that ourselves as a credible value,” said Neil Millar, CAISO’s executive director of infrastructure development.

“Natural gas prices and transmissions outages are the main drivers of congestion,” said Yachi Lin, NYISO’s senior manager of transmission planning. “Neither of those can be forecasted with absolute certainty.”

FERC shouldn’t approve any additional processes for RTOs and ISOs to manage either, said Craig Glazer, PJM’s vice president of federal government policy.

“The WATT proposal is very thoughtful, but it calls for a whole new process … outside of the existing [Regional Transmission Expansion Plan] planning process,” he said. “One thing we don’t need is another process outside of that.”

Instead, Glazer asked the commission to consider a nationwide solution to deploying GETs, given the complexities of seams relations.

“If there is any topic that cuts across the RTO and non-RTO boundary, it’s this topic,” he said. “Whatever you do, apply it across the country.”

Glazer also asked FERC to “go on the record” and state its desire for system operators to consider deployment of GETs and create a record of possible strategies. He also wanted the commission’s guidance on how to get pilot programs operational. Finally, he asked FERC to reconcile some its existing policies related to Order 1000 and transmission incentives.

PJM and other RTOs could serve as a testbed for these new devices, Glazer said, and create a record of their own that details proven technologies that “add value but offer implementation challenges.”

Millar questioned the idea of a nationwide approach. “I’m not sure a one-size-fits-all solution is what’s needed,” he said. “We worry it risks a duplicative process of what we are already doing.”

Renewables Integration

Kicking off a discussion that explored how GETs can be incorporated into the transmission-planning process, Jeff Webb, MISO’s senior director of transmission planning and competitive development, said improving existing grid investments “is an important element in developing the most cost-effective transmission grid in both the near- and long-term planning horizons.”

Webb said advances in generation technologies and other drivers are increasing renewable integration “at a dramatic pace.” He pointed to “unprecedented” levels of wind and solar resources seeking interconnection.

“As the fuel mix of the fleet continues this evolution from carbon-based to renewable sources, these new inverter-based technologies put enormous stress on the transmission grid and bring new challenges to maintaining adequate and stable performance,” Webb said.

MISO’s regional planning process “can accommodate an all-of-the above approach to developing transmission solutions to meet needs, with input from the diverse stakeholder community,” he said. “At the present time, given the transformation in generation resources evident in MISO, enabling a substantial jump in bulk delivery capability is the much more pressing need.”

Drew Clarke, lead integrated planning coordinator for Duke Energy, said the company took a different approach to future planning in 2016, when it created an integrated system and operations planning strategy. Recognizing the “significant transformations underway,” he said Duke moved toward “a more holistic view of infrastructure investment, with the goal of modeling and evaluating options never contemplated before or [using] existing technologies in new ways.”

Energy storage is one technology gaining tremendous momentum, he said.

“One of the challenges is the uncertainty of how non-traditional solutions, such as energy storage, will be classified by regulatory bodies,” Clarke said. If energy storage is classified as a generator, “then the resource would need to go through the interconnection queue along with other generators. From a timing perspective, this could limit the feasibility of this alternative as a transmission or distribution solution, since traditional wires solutions would not be subject to this additional delay.”

“It’s important to recognize [that] different technologies and solutions might be more effective in different solutions. Give us the flexibility,” he said.

Exelon Senior Vice President of Transmission and Compliance Mike Kormos said most “nonconventional transmission technologies” are not at a scale to drive down costs.

“They’re getting better, but they’re not quite there,” he said. “[They] are difficult to compare to more conventional transmission alternatives. Some of these challenges may diminish with time as the costs of these new nonconventional technologies fall.”

Kormos said most of the GETs listed in FERC’s notice for the workshop would be ineffective in meeting reliability needs. Referring to dynamic line ratings (DLR) and some power-flow control technologies, he said they might help “alleviate congestion in some instances, but system planners may not be able to depend on them to meet reliability needs under current assumptions used in transmission planning.”

“System planners must plan for the worst-case scenario when these technologies may be ineffective, given outages on other transmission facilities or adverse ambient conditions,” Kormos said.

The competitive environment and the RTO/ISO transmission planning processes both present challenges to deploying GETs, he said, noting there is no easy answer.

“A utility must attempt to minimize costs and risks, even if that means forgoing opportunities to gain experience with technologies that, over time, will become more cost effective,” Kormos said. At that point, grid operators ultimately select the more cost-effective solution. “Here, the benefits and risks are not necessarily aligned,” he said. “The responsibility to make this determination is a responsibility that an RTO/ISO may not desire to assume.”

Babak Enayati, manager of technology deployment for National Grid, said that by integrating renewable energy, new technologies deliver low-carbon resources, reduce the cost to serve customers, improve asset management, reduce operation and maintenance expenses, and improve resilience.

He focused his comments on dynamic transformer ratings (DTR), substation automation and storage. Enayati said National Grid installed DTR technologies on two transformers in July, estimating more accurate megavolt-ampere power ratings. The company has also increased the deployment of digital substation technologies that lead to quicker and lower-cost substation construction with a smaller environmental footprint.

Thanks to a 6-MW, 48-MWh battery on Nantucket Island and other installations, National Grid has concluded that “energy storage can offer a variety of benefits and challenges,” Enayati said.

When paired with flow-controller devices, he said, battery storage “may be the least-cost solution to address case-specific reliability issues on the transmission network” and can provide voltage and frequency services.

However, some storage inverters are manufactured outside the U.S, creating cybersecurity issues, Enayati said, “and some RTO/ISO regional planning processes do not consider energy storage as a potential solution to identified reliability needs.”

Who Benefits?

Unused transmission capacity is a challenge that can be met with technology, said Swaraj Jammalamadaka, vice president of transmission at Apex Clean Energy.

“You have, just in PJM [alone], over 1,200 transmission facilities that are loaded less than 20%, so from a generation developer’s perspective, when we get hit with congestion in the market, it’s a little concerning to us that there are lines next to ours not loaded anywhere close to their capability but we still experience congestion in the market,” Jammalamadaka said.

There’s “definitely a lot of value” for equipment that can control or redirect power flow while increasing transmission adequacy and enhancing system reliability, he said.

A GET most often works similar to transmission in terms of delivering benefits, so the company enabling the technology might not be the financial beneficiary, Jammalamadaka said.

Jeff Dagle of the Pacific Northwest National Laboratory said that while the cost of GETs has been coming down, historically there has been a cost barrier to implementing things like phase-shifting transformers that can redirect power flow on the network.

“A lot of times, the grid assets … are based on a post-contingency analysis,” Dagle said. “So during normal day-to-day operations, if you just look at the asset utilization, you might see relatively low numbers, but yet those resources are really designed and justified based on post-contingency situations.”

Other Perspectives

Jack McCall, executive vice president of California-based Lindsey Manufacturing, which provides DLR systems, said he favored DLR over ambient-adjusted ratings (AAR), which he thinks should not even be considered as GET.

“We recognize the familiarity, assumed simplicity of implementation and perceived low cost of AAR. However, AARs do not truly provide situational awareness — merely a perception of awareness,” McCall said.

Pablo Ruiz, CEO of NewGrid, a utilities software developer in Boston, touted the benefits of topology-optimization technology, which automatically reconfigures power flow on the grid around congested elements.

“In terms of grid resilience and security impact, in several historical cases with overloads during extreme weather events, including heat waves [and] wildfires, we have found [the technology provides] in some cases complete relief,” Ruiz said. He pointed to his firm’s success in working with National Grid to improve system capability across a broad area of the U.K.

Monitor Patton questioned the advantage of treating topology different from other forms of optimization.

“When I listened to Pablo’s topology optimization, I don’t see how it’s different from other optimization improvements,” Patton said. “In fact, if [RTOs/ISOs] were to implement it, I think it would have to be implemented in their current set of models and tools because, for example, MISO and New York both run models every 15 minutes to optimally continue gas turbines, often for congestion relief.”

Ruiz responded that topology optimization “enables visibility on operational options, of the options that are not visible by and large today to the operators. In the end, software is certainly optimization. It has to be integrated in a different process, some processes require less integration, those are the days ahead and months ahead.”

MISO’s Webb said the question of who determines what qualifies as a GET can be a complicated. He counseled caution before RTOs adopt a particular technology.

“Maybe it depends if we’re talking about whether it needs to be isolated in definition from other types of transmission for other types of treatment, and I’m not sure we’ve resolved or addressed that,” Webb said. “Once you have an established technology that is mature, then the RTO can put that in its tool bag, if you will, with the collaborative planning process.”