Blackout Blues

Although the jury is still out as to exactly what led to a situation where 50 million customers in New York, the Midwest and southeastern Canada were suddenly without power on August 14, 2003, many electrical engineers and consultants seem to agree that the state of the nation's transmission system deserves some of the blame.

By Barbara Horwitz-Bennett, Contributing Editor December 1, 2003

Although the jury is still out as to exactly what led to a situation where 50 million customers in New York, the Midwest and southeastern Canada were suddenly without power on August 14, 2003, many electrical engineers and consultants seem to agree that the state of the nation’s transmission system deserves some of the blame.

“Utility investment in transmission is the lowest it’s been in 10 years,” notes Andy Montano, P.E., an electrical senior technical advisor with Bala Consulting Engineers, Cranberry, N.J. “On the one hand, utilities are being required to move power, but there are no incentives to expand the system in order to keep pace with the power coming in.”

The main reason, say a number of engineers, is that electric utility deregulation has affected only power generation, whereas the nation’s transmission and distribution systems have remained regulated, thereby creating a lack of incentive for utilities to perform necessary upgrades.

“Deregulation has created a good deal of uncertainty and hesitance [on the part of utilities] to invest in the upkeep of the transmission system because of the unknown as to whether they will be able to get rates commensurate with these investments,” explains Mike Pearson, P.E., a principal with The SmithGroup’s electrical division, Phoenix. “If there is uncertainty about the ability to charge a fair price, then the purse strings are tight.”

In addition, the deregulated generation market in some states has put newfound competitive pressures on utilities. “Everyone is getting on the bandwagon for generating capacity, so utilities are being forced to generate for less and they’ve had to cut costs,” says Rajan Battish, P.E., an associate and senior electrical engineer with RTKL, Baltimore. “So, in order to remain competitive, they’ve delayed infrastructure upgrades.”

Anil Ahuja, P.E., a senior vice president with CCJM Engineers, Chicago, agrees that the way things are now set up, the power industry is much too focused on the stock market and not enough on improving the nation’s electrical infrastructure. Ahuja also faults a lack of nationally-enforced standards as contributing to a situation where regional transmission providers have their own original sets of equipment and systems.

“When there’s a failure, there is no spare inventory because everyone uses their own equipment, so repairs can’t be made in a short period of time,” he explains.

In addition, these varying regional systems don’t function so efficiently as a national system. “The transmission system is scotch-taped together at the edges,” claims Lindsay Audin, president of Energywiz, a Croton, N.Y.-based energy consulting firm.

Although Audin doesn’t believe the system is “third-world,” as it has often been portrayed recently by the mainstream media, he does describe the U.S. electrical grid as “Balkanized” in that the regional systems have evolved over time following different sets of rules and operating independent of one another.

SmithGroup’s Pearson concurs. “The system is not third-world by any stretch, as former Secretary of Energy Bill Richardson called it, although parts of it are quite old and in need of maintenance.”

A national need

In order to address this shortcoming, Audin and other energy consultants suggest that at least some level of national oversight is sorely needed. “Rules for transmitting power need to be established where if a utility doesn’t upgrade, there will be penalties,” Audin posits. He adds, however, that the only way this can happen is if it is politically supported and established, and no such political will exists at this time.

As things currently stand, independent system operators (ISOs) are allowed to study transmission problems, but not enforce upgrades. On the other hand, regional transmission organizations (RTOs) could theoretically have that enforcement power. Unfortunately, no RTOs currently exist.

At the federal level, the Federal Energy Regulatory Commission (FERC), Audin claims, is unclear as to what power it actually has outside of enforcing upgrades at a time of national emergency, such as war.

Jim Owen, director of media relations for the Edison Electric Institute, Washington, D.C., also stresses the importance of the government empowering agencies such as FERC or the North American Electrical Reliability Council (NERC) with the authority to enforce transmission upgrades. Owen believes that increased national authority would also assist with the arduous process of obtaining permits and approvals for building new transmission lines, a process that is frequently and easily hindered by the many landowners who manifest the “NIMBY” attitude—Not In My BackYard.

Audin explains that right now, only a state agency or public utility commission can move such an upgrade forward. However, in order to accomplish this, the organization must receive permission from all states involved, which is a process that can easily be derailed. “People don’t like the unsightly view of transmission lines in their backyard,” he says.

“Currently, there are so many restrictions on the power industry, so transmission and distribution projects progress very slowly,” says Syed Peeran, P.E., PhD., chief electrical engineer, WB Engineering & Consulting, Woburn, Mass.

Of course, even with the required permits, the cost of building new lines is extremely expensive, running between $500,000 to $1 million per mile of high-voltage lines, according to Montano. And while building underground may be a more environmental and neighborhood-friendly option, the cost is ten times as much.

Moreover, exactly where that money might come from is not clear. Owen suggests that an amended tax code with an accelerated depreciation schedule for such capital assets would be a good start. Owen, whose trade association represents investor-owned electric power companies, also explains that transmission facilities are currently on a 20-year depreciation schedule. If that were to be changed to 15 years, it would assist utilities in making those investments. He adds that the industry is currently spending $3.5 billion per year on infrastructure, but that amount should really be $5 billion in order to keep pace with the power transmission demands on the system.

Ahuja laments the fact that this lack of investment has created a situation, most notably August 14, where so much money was lost. However, Audin explains, “There’s no way to connect lost commerce to paying for new transmission lines, other than through the government.”

Incidentally, Audin has begun touting a novel idea—blackout insurance—which would use a financial instrument to circumvent upgrading the system. End users would simply accept a lower level of electrical reliability, while simultaneously protecting their resources through insurance (see “Wanna Buy Some Blackout Insurance?”).

Other upgrade options

At the same time, there are various less costly ways to upgrade the system. Battish explains that by utilizing what’s known as FACTS—Flexible AC Transmission Systems—utilities could reuse and upgrade existing infrastructure.

“Putting additional wires on existing towers is almost a no-brainer,” claims Montano. “This is a fairly quick and relatively inexpensive way to improve the capacity of the existing lines and doesn’t require permits.”

Another approach is to use wires with steel cores. “These wires take more heat without sagging and can stand overloads for a much longer time than normal wires,” he adds.

Newer technology also gives utilities the option of installing gas-insulated switchgear and transmission lines, as opposed to oil-insulated equipment, says Battish. The advantage of gas is that it’s more compact, safer and environmentally friendly.

Yet another inexpensive way to bolster the system is through the installation of short-circuit limitators which work to prevent a cascading effect in the event of a fault at the substation, Battish adds.

Deregulation in question?

In the meantime, questions have been raised as to what extent deregulation may be held accountable for the current, less than ideal status of the nation’s transmission system. “Deregulation is wonderful for generation, but the weak link in the chain is getting power to the customers,” claims Battish.

For example, Pearson points out, in Arizona, one of the few states that has not deregulated, the state seems to have managed to maintain its transmission system. “Phoenix has an excellent reputation for reliability,” he claims. As a result, Pearson questions the nation’s approach to deregulation.

“I’m not sure it’s in our economy’s best interest to deregulate, because so much depends on the integrity of the nation’s electrical system,” Pearson states. “Any deregulation has to take into account the entire system and the cost of maintaining and improving that system. If we are going to deregulate, it has to be more comprehensive.”

Taking a slightly different approach, Audin clarifies that deregulation didn’t directly create a weakened system, but rather it exposed the pre-existing situation of an outdated transmission system requiring significant upgrade.

Peeran goes a step further. “I don’t think deregulation had any impact on the situation, although it is possible that utilities have been a little lax on maintaining their systems,” he suggests.

In any case, the magnitude of what took place on August 14, 2003, is forcing all those affected to seriously analyze the situation. “One incident like this amounts to huge financial loss,” warns Peeran, “not to speak of the danger from a security standpoint. Improving the system is vital to the nation.”

Similarly, Owen concludes, “If there’s a silver lining to this whole situation, it is that people are beginning to pay more attention to the transmission system, which is the backbone of the entire system.”

Let’s just hope that people’s attention stays focused improving transmission.

Wanna Buy Some Blackout Insurance?

Due to the technical, economical and political complexity of upgrading the nation’s power transmission system, veteran energy consultant Lindsay Audin, president of Energywiz, Croton, N.Y., has come up with what he sees as a more practical approach to the situation: blackout insurance.

“My suggestion to organizations who are very vulnerable to power loss is to insulate themselves from damage by addressing the situation through a financial rather than technical standpoint,” he says.

Audin explains that by the time an end user pays to install a backup generator, including fuel storage, utility hookup, environmental compliance and fire insurance, it takes five to 10 full blackout days to pay off the investment. On the other hand, by taking out blackout insurance, the organization would only have to pay small annual premiums in exchange for protecting its assets.

However, Audin concedes that such an approach would require a different mindset, namely, “accepting a lower level of electrical reliability and choosing to utilize a financial instrument to get around upgrading the system.”

Although there isn’t necessarily such a product on the market as yet, Audin has been working with the insurance industry to bring the idea to fruition.

Facts on Power Factor

With the availability and reliability of the nation’s electrical grid seriously being called into question, especially after the major blackout that swept through New York, the Midwest and southeastern Canada in mid-August, an argument for the importance of improving power factor can be made.

“If you could take a significant portion of reactive power that is not used and convert it into usable power by improving power factor, you could alleviate load on the entire grid,” explains Mike Pearson, P.E., a principal of The Smith Group’s electrical division, Phoenix.

However, the responsibility and expense of improving power factor pretty much falls on the end user. And while utilities used to penalize their end users with low power factor in order to motivate them to improve, penalties have become less common as a result of deregulation, according to Anil Ahuja, P.E., senior vice president, CCJM Engineers, Ltd., Chicago.

Another difficulty is that the payback period for investing in power factor improvement equipment like capacitors, synchronous machines and harmonics analysis can easily take 10 years, whereas end users are often only focused on first cost, and not on long-term maintenance expenses.

“End-users’ average power factor is 0.8,” explains Lindsay Audin, president, Energywiz, Croton, N.Y. “To improve to 0.9 across the board would require an enormous upgrade.”

Of course, some engineers suggest that better power factor is better for electrical equipment.

“Adding capacitors decreases the current on the incoming lines and the equipment usually works better, especially for large motor loads,” explains Andy Montano, P.E., electrical senior technical advisor, Bala Consulting Engineers, Cranberry, N.J.

However, Pearson warns that dropping in a large quantity of capacitors can cause voltage transients which can lead to other problems for the end-user, such as voltage surges and network disruptions.

As an alternative, Pearson suggests a slightly different strategy.

“I’d like to a see a pilot project where we use monitoring systems to bring smaller quantities of capacitors on-line on a constant basis, rather than as a block load,” he offers. “I think this is a strategy that has some promise.”