Shoring Up U.S. Transmission Means Facing FACTS

By Steven M. Brown, Senior Associate Editor

A dearth of investment in transmission over the course of 20 years—combined with on-again, off-again deregulation and restructuring of the power industry—has left the U.S. transmission system in a state of confusion and relative instability.

Since the transmission boom of the late 1960s and early 1970s, construction of new transmission facilities has lagged behind both the construction of new generation and growth in peak power demand. This disconnect has led to the present concerns with bottlenecks and congestion in certain parts of the country and general transmission system instability nationwide.

The problem is far more acute in some parts of the country than others. Inadequate transmission capacity along the Path 15 corridor connecting northern and southern California, for example, has received a portion of the blame for the California energy crisis of 2000. Likewise, on the other side of the country, transmission constraints in parts of the Northeast have been a major concern for ISO New England for the last three summers. These are two of the extreme examples, but concerns over transmission grid adequacy are not limited to the West Coast or the Northeast. It is a nationwide concern.

Improvements are being made—most notably of late, the long-awaited upgrade to Path 15 in California appears finally to be moving forward—but siting new transmission towers and lines is a laborious, contentious process.

One possible fix for the overburdened transmission system is the application of flexible ac transmission system (FACTS) technology. In the paper “Of Chips, HiTS, Bits and Bytes: Building the Powerline Paradigm” (Appendix A “Tools for Transmission”) written for the Center for the Advancement of Energy Markets by Philip M. Marston, an attorney practicing as Marston Law, FACTS is described as “combinations of solid-state switches and computerized automation that enable nearly instantaneous customized control of ac power flows, far faster than traditional electromechanical ac switches.”

FACTS technology is supplied in the United States by such companies as ABB, ALSTOM T&D, Mitsubishi Electric Power Products, and Siemens Power T&D. The devices can be used to move power along transmission lines from one point to another in a very precise way, to help stabilize the transmission system after a disturbance, to relieve or even eliminate congestion, to tie grids together, to integrate distributed generation resources into the grid and to combat the phenomenon of loop flow—all of which are very attractive capabilities given the state of the transmission network and the Federal Energy Regulatory Commission’s (FERC’s) vision of a restructured bulk power market.

But, despite its potential to provide a much-needed boost to the transmission system, adoption of FACTS technology has been less than rapid in the United States. According to the industry experts interviewed for this article, U.S. utilities have been relatively slow to embrace FACTS primarily due to the cost of FACTS devices, industry uncertainty stemming from restructuring issues, and a general lack of education about FACTS.

The Cost Issue

Cost has generally been viewed as one of the main stumbling blocks holding back widespread implementation of FACTS devices in the United States. But cost is a relative issue. While FACTS may be expensive compared with mechanically switched capacitor banks, cost becomes less of a barrier when one compares a FACTS implementation with the construction of a new line.

FACTS proponents also point out that the technology’s dynamic nature makes comparisons to traditional mechanically switched technology invalid.

“The biggest misrepresentation I see is that people want to compare FACTS to conventional technology,” said Gregory Reed, marketing and technology vice president for Mitsubishi Electric Power Products Inc. (MEPPI). MEPPI has been involved with FACTS since the technology’s birth in the early 1970s and, in the United States, has supplied the technology to utilities in the Northeast (Vermont Electric Power) and on the West Coast (San Diego Gas & Electric).

“If you compare costs, yes, FACTS will be more expensive than a mechanically switched capacitor bank,” Reed said. “But that’s not an apples-to-apples comparison. These are dynamically responding devices. They go way beyond what the conventional technology can do.”

It is also an accepted fact that the cost of the technology is dropping and will continue to drop as its component parts become less expensive.

“It (the cost of FACTS devices) will drop. There’s no doubt,” said Abdel-Aty Edris, the technical manager of the Electric Power Research Institute’s (EPRI’s) FACTS program. Since it began working with FACTS in the 1980s, EPRI has been perhaps the chief proponent of the technology in the United States. EPRI has been actively involved in FACTS projects for the Tennessee Valley Authority, American Electric Power, the Bonneville Power Administration, and the convertible static compensator project at the New York Power Authority’s Marcy substation, among others.

“FACTS relies heavily on semi-conductor switches,” Edris said. “This is probably 50 percent of the cost. In the future, the cost of these devices will go down, so you’ll get a big impact on the total cost.”

Falling costs may make it easier for utilities to cost-justify FACTS in the years ahead, but Martin Luckett, commercial director of power electronic activities for ALSTOM T&D, said the cost of FACTS still plays a part in his utility customers’ reluctance to implement the technology. Once the customer understands the potential benefits, however, the decision can become much easier—particularly for utilities with acute grid stability problems.

“It takes a lot of effort to get a customer to accept an SVC or other FACTS device, but once they have them, they can’t do without them,” Luckett said. “Generally, people will say, ‘We’ve always used breaker-switched capacitors. That’s always worked in the past; it will work now.’ Unfortunately it won’t, but it’s difficult to show why without the entire system collapsing.

“Unfortunately, in some states they’re getting to that point very quickly,” Luckett said.

Classic Case in the Northeast

For a utility in dire need of a transmission system boost, the issue of FACTS cost can quickly become a non-issue. And if there has ever been a region in urgent need of FACTS technology, it is southwest Connecticut.

Concerns about transmission capacity in southwest Connecticut have been well-publicized the last three years, with ISO New England periodically warning of the potential for blackouts in that part of the state due to transmission constraints. Northeast Utilities has proposed construction of a new 345-kV line to bring relief to the area, but, as has been the case in many other parts of the country, Northeast’s new construction proposal has been met with much debate. At the time of this writing, the proposal was still awaiting approval.

With new construction on hold, Northeast Utilities and its subsidiary Connecticut Light & Power Co. (CL&P) have installed FACTS devices in three substations in far southwest Connecticut to solve the area’s voltage disturbance problems and increase the reliability and flow of electric power in the area.

“We needed to find a way to get a little more out of our existing transmission and distribution facilities in that part of Connecticut to give us a little more time until we could get an upgrade of transmission into the area,” said Frank Poirot, a spokesperson for Northeast Utilities.

The three FACTS projects—all in the Connecticut Light & Power service territory—consist of two D-VAR (Dynamic VAR) voltage regulation systems supplied by American Superconductor (with related GE Industrial Systems equipment) installed in substations at Southbury and Brookfield, and a STATCOM (static compensator) device supplied by ALSTOM T&D in the Glenbrook substation. All three are in the southwest quarter of the state where demand for electricity has been outpacing demand in the rest of the state. As demand has increased, the potential problems posed by inadequate transmission facilities have simmered on the verge of boiling.

“We came very close to a serious outage in June 2001,” Poirot said. “A good portion of Stamford was left without power on a Sunday morning because of voltage fluctuations in the area. We realized we had been given a warning shot, and we had better act on bringing some stability to that part of the grid.”

Poirot said the completed D-VAR projects are providing support now, and the STATCOM project will be completed in plenty of time to help the region through summer 2004.

“By the summer of 2005, we’re hoping to have the first leg of our 345-kV upgrade on-line,” Poirot said.

All three projects in Connecticut have been done on an accelerated basis. The two American Superconductor projects were awarded in early February and were already completed in June. The ALSTOM project also was announced in February and is on schedule for completion in December. These were fast-track implementations, but ALSTOM’s Luckett said that a quick turnaround is becoming more important to utilities implementing FACTS.

“System conditions are changing daily,” Luckett said. “The need to get the right equipment in the right place as quickly as possible is becoming more and more prevalent.”


In 2001, Vermont Electric Power Co. installed a Mitsubishi Electric Power Products STATCOM system at its Essex substation to combat voltage instability and power quality problems. Similar work is now being done in Connecticut Light & Power substations by ALSTOM T&D and American Superconductor. (Photo courtesy Mitsubishi Electric Power Products Inc.)Click here to enlarge image

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The work being done at Northeast Utilities to promote voltage stability is similar to work that Mitsubishi did in 2001 at Vermont Electric Power Co. (VELCO). Like Northeast Utilities, VELCO found FACTS to be a viable alternative to building new transmission lines.

“VELCO was faced with a voltage stability limit as well as a power quality issue,” MEPPI’s Reed said. “They looked at a number of solutions, the most viable being a new 345-kV transmission line or, to achieve the same effect, a FACTS device. In the end, FACTS was the lowest cost choice by about a third.”

In May 2001, VELCO placed a STATCOM system on-line at its Essex substation near Burlington, Vt., to provide dynamic voltage support and reactive compensation. Like the current projects at Northeast, the VELCO project primarily helps to stabilize the grid and compensate for heavy summertime usage increases.

“It (the Essex STATCOM system) was implemented in less than a year and a half, and it’s been a tremendous success,” Reed said.

The Outlook for FACTS

Several contracts for U.S. FACTS implementations have been announced since the beginning of the year. Of recent note are the three projects for Northeast Utilities and CL&P, an ALSTOM static var compensator project for Xcel Energy to help with the interconnection of wind farms into the power grid, and two recently announced ABB projects at Idaho Power and Nevada Power to replace existing installations.

This empirical evidence would seem to suggest a healthier outlook for U.S. adoption of FACTS solutions. ABB’s Conny Wahlberg said that his company has calculated that so far this decade, the FACTS market worldwide has grown 50 percent compared to where it stood in the 1990s. He predicts a 7 percent annual growth rate for the FACTS market going forward.

The experts interviewed for this article agreed that power industry policy will likely have a great impact on whether or not FACTS flourishes in the United States. The controllability FACTS provides and its ability to facilitate the interconnection of grids may make it a more attractive tech-nology as FERC moves the U.S. power industry toward the creation of large regional RTOs and a seamless grid.

“FERC policy is absolutely key to this. Network control is the fundamental reason for FACTS devices,” Luckett said. “If there’s a coordinated approach across the network with collective responsibility for that network, and some sort of recognition of the benefits of FACTS devices globally, then it could be implemented in a manner where the benefits, and the costs, are shared across the network.

“If FERC, the RTOs and the utilities themselves go in that direction, there will be an enormous market for FACTS in the U.S.,” he said.

MEPPI’s Reed agrees that FERC’s RTO and bulk power market design policies could have a major impact on FACTS acceptance in the United States.

“If we do indeed end up with large regional grids of some type that would need seamless interconnection, it could certainly lead to a greater amount of application for this tech-nology,” Reed said.

In the meantime, EPRI is working to educate not only utilities, but also policy makers about the merits of FACTS. Edris said his organization supports FERC’s efforts to incentivize utility investment in technologies. He believes the future well-being of not only the power grid, but the economy as whole, is reliant on technologies such as FACTS.

“We talk about the digital economy and the digital society,” Edris said. “There’s no other way to make the digital society work than with power electronic controllers.”

Author

  • The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at Jennifer.Runyon@ClarionEvents.com.

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The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at Jennifer.Runyon@ClarionEvents.com.

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