Centralized federal oversight sounds good, but what about squabbles between separate federal agencies?

Some cite California's notorious "Path 15" as an example of how transmission bottlenecks can stifle electricity competition, but the problem extends beyond the West Coast. In reality, TLR events (transmission loading relief) rose significantly across the country in 2000, compared to the previous three years. ()

In the upper Midwest, Wisconsin Governor Scott McCallum released a report in June that underscored his state's unique electricity geography and its vulnerability to a weak transmission infrastructure. As explained in the report (), the state resembles an isolated transmission "peninsula," as it is nestled between two Great Lakes. It also straddles the dividing line between two regional reliability regions, the Mid-Continent Area Power Pool (MAPP) and the Mid-Area Interconnected Network (MAIN), that are linked only by one major line. So Wisconsin Public Service Corp. and Minnesota Power Inc. have been at work to link the two regions with a new line.

Further to the east, American Electric Power (AEP) has spent a decade trying to certify a new a 765-kilovolt (kV) line to link southern West Virginia with southwestern Virginia. That project finally won approval last May from the Virginia State Corporation Commission. And in California, Pacific Gas & Electric Co. and the state's Independent System Operator (ISO) have set 2004 as a target date for completion of upgrades to Path 15.

These three examples help show why political momentum has grown for federal action to simplify the process of transmission line siting and certification. President Bush's proposed national energy policy, released last spring, calls for a "national grid." Yet these examples also show that the problem is not so simple to solve.

First, the electric utility industry began its TLR program only several years ago, so a long history of data is not yet available. Also, TLR events can fluctuate with the weather and with market price behavior, making such events perhaps not entirely reliable as an indicator of transmission performance. Second, it remains difficult to evaluate need for grid expansions or to put a value on the worth of grid upgrades, since decisions are made locally, while the cost-benefit equation takes on a regional character. Finally, as shown by AEP's experience in southwest Virginia, transmission owners may not be altogether uncomfortable with the idea of the states retaining decision-making over the certification of transmission lines.

TLRs: An Evolving Metric

Figure 2 shows how the number of TLR events rose last year more or less across the board for security coordinators. AEP, in its role as security coordinator for ECAR (East Central Area Reliability Coordination Agreement), led the pack with the most TLRs declared in 2000. (The statistic represents 13 control areas within the ECAR region, and not just AEP's company-specific area.)

Note, however, that TLR events can fluctuate significantly from year to year, depending on weather in the various regions. Says Scott Moore, vice president, transmission operations at AEP, "A lot of TLRs are dependent upon where the markets are at any given time. ... Last year [for example], the flows were quite abnormal to what we had seen historically. This year they're more typical."

Tim Gallagher, manager of technical services at NERC (the North American Electric Reliability Council), explains further: "[TLRs] are spurred on by transmission congestion, but the transmission congestion in a lot of cases is just driven by the weather. [For example] if it's cool on one side of that transmission interface and it's hot on the other side, and it makes it economically attractive to try to move the resources across that transmission corridor, then there's a practical limit to how much you're going to transfer if you're going to get into transmission congestion. [But] it doesn't always mean that it's always going to be like that. The weather can change significantly."

Take, for example, the flowgate between Ontario and Michigan, known as Queen Flow West, or QFW, Gallagher points out.

"Historically, that has been a heavily congested transmission interface and there have been times when Ontario has not been able to transfer as much power as it would like to the west, across into Michigan, and there have been a lot of TLRs called there in the past. Last summer, because it was so cool in the upper Midwest, I don't think they had any TLRs in that flowgate the entire summer. So a lot of it's driven by weather."

Also, the TLR metric is relatively new. "The whole industry has been learning as we've been going on, and it basically has been modified about every six months as we learn how to do this on a regional and national basis," adds Moore.

Three Lines, Three Stories

Virginia/West Virginia. Previously dubbed the "Wyoming-Cloverdale" line, AEP's long-planned grid project was renamed recently as "the 765-kV line"-the company adopted the more generic name after dropping efforts to route the line through Cloverdale (outside Roanoke). As approved by Virginia regulators on May 31 (), the line would begin in Wyoming County, W.Va. and terminate near the Jackson's Ferry substation, south of Pulaski, Va. "And there have been numerous routes on the table [between the first and last proposal]," says Todd Burns, corporate communications manager at AEP.

Yet even after four years of deliberation, the Virginia commission sounded almost ambivalent about its decision.

"Unfortunately, any of the alternative [routes] we have considered would have undesirable impacts that may, in some individual instances, be significant," said the commission in its order. "Nevertheless, the record demonstrates clearly the potential negative consequences of failing to take appropriate action." West Virginia gave the green light for the 33 miles of line in that state in 1998. The Virginia segment is roughly 57 miles long. The expected service date for the 765-kV line would be December 2004.

Wisconsin. In an effort to ease the strain on the King/Eau Claire line, which runs between the MAIN and MAPP regions, Wisconsin Public Service Corp. and Minnesota Power Inc. have proposed to build a 250-mile, 345-kV line between Wausau, Wis. and Duluth, Minn. With approval already in hand from the Minnesota PUC for the short stretch of line that would run through that state, the two companies now await approval from the Wisconsin Public Service Commission. The project, known as Power Up Wisconsin, has several different routes under consideration.

The project announcement came after an incident occurred that brought attention to the region's vulnerability. On June 25, 1998, the King/Eau Clair line went down, bringing several Midwestern states and Canadian provinces to the edge of a full-scale, regional blackout. A benefit of the Wausau-Duluth line is that it would take a path different from King/Eau Clair, the only existing 345-kilovolt line linking Minnesota and Wisconsin. That should reduce the risk of a single storm knocking out both lines. Further, the new line would provide a Wisconsin-Minnesota electrical connection that would bypass heavy power flows through the population-dense Minneapolis-St. Paul area.

For more detail, see the initial ten-year assessment issued June 1 by American Transmission Co., the stand-alone "transco" that now owns and operates most of Wisconsin's electric grid (www.atelle.com/newsroom/10Yr_Plan.pdf).

In his energy plan released in June, Gov. McCallum listed the proposed Duluth-Wausau line as a priority, and said that approval by the PSC could come as early as the end of the summer.

California. To the west, California's Path 15 represents a series of parallel North/South lines that form a bottleneck in restricting power deliveries sent up from Southern California when hydroelectric output available to Northern California runs short.

In February, the California ISO released its "Path 15 Cost Analysis Study," (www.caiso.com/docs/2001/02/02/20010 20215200926969.html). It concluded that the total additional cost of energy and ancillary services from Path 15 congestion was up to $221.7 million between September 1999 and December 2000.

Ziad Alaywan, managing director of engineering at the California ISO, wrote at the time that the results of the study should "support and justify a Path 15 transmission upgrade to alleviate the Path 15 congestion costs to the consumers of the state of California."

The upgrade is estimated to increase the non-simultaneous rating on Path 15 from the current south-north limit of 3,750 MW to between 5,000 and 5,500 MW or more. In addition to reducing costs, one intention of the project would be to prevent load interruptions such as what occurred in Northern California in January 2000. An April 13 letter from PG&E solicited interest in addressing the project through a "Regional Planning Review Group." PG&E also has initiated the Western Systems Coordinating Council's three-phase rating process; a progress report for Phase 1 was expected at the end of July.

Measuring Need and Benefits

Bernie Pasternack, director, transmission planning at AEP, explains why it is not so easy to determine need for a transmission upgrade, or to judge the benefits when work is completed.

"The primary reason for building the line [AEP's 765-kv project] is really to supply the native load in AEP's service area [but] I'm not sure there's any real good metric that tells you how much it improves. One way of looking at it is that without the line we know that we had a number of contingency situations that would cause serious problems including blackouts."

Without the line, AEP calculates over 30 different combinations of line outages that could cause problems to the system. With the proposed line in service, says Pasternack, there are essentially no contingencies that would cause any problems.

"Another way you could measure," he adds, "is you look at the amount of customer load in that service area that you could serve reliably ... With the new line, we estimated that-and these are really pretty crude numbers-we could probably serve additional load for a period of about 7 to 11 years... . That's just a very rough rule of thumb. I wouldn't take that to the bank, but it's just another way of getting an idea of what value the new line provides for us."

NERC's Gallagher offers another interpretation. "A lot of time the reason that [companies] cannot get siting approval to actually construct a facility is because it's difficult to demonstrate the need for the facility," he says. "For instance, if a line is going to go through three different states, the states on either end can demonstrate to their constituents what the benefits of that transmission line will be, but the state in the middle has a very difficult time demonstrating the benefit. So, it's almost impossible to get the line built and approved."

AEP's 765-kv line is part of a joint program that involves an interconnection with Virginia Power. Pasternack says that AEP studied the combined benefits in its 765-kV line effort, finding that "with the final approved route ... the transfer capability increases on the order of about 2,000 megawatts."

And what of the elusive TLR metric? The likelihood certainly is that TLR numbers will improve generally, but again, much depends on X-factors such as the weather. "In terms of TLRs," Pasternack adds, "it's really impossible [to speculate] what will happen. We would hope that with 2,000 MW of additional capacity, we wouldn't be calling very many TLRs, at least not on the facilities that are limiting the transfers today."

Reforming the Process

Since transmission lines often cross state lines, some favor turning the whole process of certification over to the federal government, most likely the Federal Energy Regulatory Commission.

"It's not going to take all of the problems away," warns NERC's Gallagher "because the folks that are impacted by the facility are still going to have their voice heard and are still going to have to be satisfied and soothed somehow. But, if you have one entity that you have to deal with-and I'm thinking it would probably be a federal entity-then that will certainly streamline the process and cut down some of the delays. You won't have to deal with 15 counties and 72 municipalities and four states. You just deal with the federal government. That will help."

Nevertheless, some utilities may have grown to like-or at least accept-the idea of state oversight. AEP suggests that federal authority might step in only as a backstop, if state-centered processes bog down.

"How do you fix it? ... AEP does not believe that we should go to full federal preemption," says Pasternack. "We believe that the states still have processes that can work, and we should allow those processes to work. But, perhaps there should be some backstop in the sense that if those processes are not working in a timely fashion, then you could go to the federal government and have them step in."

Yet Pasternack does acknowledge problems with projects that affect more than a single state.

"The multi-state part of it certainly has caused us some difficulty because, you know, each state wants to wait to see what the other state is going to do," says AEP's Pasternack. "And then there are issues around the question of, 'Well, gee, the route is impacting my state more than it's impacting the other state. There ought to be a different route that impacts my state less ... .'"

And centralized federal control can mask problems that arise when multiple federal agencies must approve a project. AEP's project, for example, involves the US Forest Service, Park Service, and Army Corps of Engineers.

"One problem we run into," says Pasternack, "is the US Forest Service, which is the lead agency for this particular line. While they were waiting for the states to determine need, they weren't willing to do a lot of work on the environmental side-which is, I guess, understandable [because] when they get into route specific work, it becomes wasted if the state decides on a different route. So you've got that issue."

And given that AEP is working with several federal agencies on the project, it's not surprising that the company sees so many sides to the issue.

"We think there needs to be some streamlining within the federal process itself," adds Pasternack. "We could still have the separate state process with the federal [government] as a backstop, but where you need federal permits, the federal agencies really have to get their act together, too."

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