Ohio-based FirstEnergy Corp. and the utility’s reliability coordinator, the East Central Area Reliability Council (ECAR), failed to assess and understand the inadequacies of FirstEnergy’s system, particularly with respect to voltage instability and the vulnerability of the Cleveland-Akron area, and FirstEnergy did not operate its system with appropriate voltage criteria, a final report issued last week by a joint U.S.-Canada task force examining the historic Aug. 14, 2003 blackout concludes.

According to the task force, FirstEnergy failed to conduct rigorous long-term planning studies of its system and neglected to conduct appropriate multiple contingency or extreme condition assessments. Also, the utility “did not conduct sufficient voltage analyses for its Ohio control area and used operational voltage criteria that did not reflect actual voltage stability conditions and needs.”

Moreover, the final report said that ECAR did not conduct an independent review or analysis of FirstEnergy’s voltage criteria and operating needs, thereby allowing the utility to use inadequate practices without correction. In addition, the task force found that some of the North American Electric Reliability Council’s (NERC) planning and operational requirements and standards were “sufficiently ambiguous” that FirstEnergy could interpret them to include practices that were inadequate for reliable system operation.

The final report follows on the heels of an interim report issued by the task force last November (see NGI, Nov. 24, 2003). Among other things, the interim report concluded that FirstEnergy and the Midwest Independent Transmission System Operator (MISO) both violated voluntary reliability standards set by NERC.

The interim report listed three groups of causes for the blackout: (i) inadequate situational awareness at FirstEnergy; (ii) FirstEnergy failed to adequately manage tree growth in its transmission rights-of-way and (iii) failure of the interconnected grid’s reliability organizations to provide effective diagnostic support.

The critical evaluation of FirstEnergy and ECAR on voltage-related issues is a new fourth group that was added to the existing set of three groups of causes mentioned in the interim report and also included in the final report.

“It is a systemic, long-term misunderstanding” of the needs to keep the transmission system within compliance of reliability rules in the FirstEnergy region, said Jimmy Glotfelty, director of the Department of Energy’s (DOE) Office of Electric Transmission and Distribution, in explaining the additional group of causes for the blackout included in the final report.

“That is absolutely critical because there was time — there were many years, in fact — for the utility and those in the area to ensure that they understood the system’s requirements when any single contingency or multiple contingency happened, and that had not happened,” Glotfely said in a conference call with reporters following the final report’s release.

During the Q&A portion of the call, a reporter asked whether FirstEnergy should have shed load in the Cleveland area on the day of the blackout.

“First and foremost, as this blackout began to cascade, as lines began to trip, after 3:05 [p.m.]on Aug. 14, shedding load was really the only thing that FirstEnergy could have done to minimize the scope of this blackout,” Glotfelty said. “So, having policies and procedures in place to ensure that load could be shed in a timely fashion in response to an emergency situation was something that very likely could have helped minimize the scope of this.”

Alison Silverstein, a top advisor to FERC Chairman Patrick Wood and a participant in the crafting of the final report, said that if FirstEnergy had shed as much as 1,500 MW of load in the Cleveland-Akron area before 4:05:57 that afternoon, which is when the 345-kV Sammis-Star transmission line went down, “the blackout would very likely have been averted or remained local only.”

Once Sammis-Star went down, “the cascade of lines that happened subsequently was almost inevitable and we’re not sure that shedding load after that point would have made enough of a difference,” she said.

Meanwhile, the final report lists more than 40 recommendations for the power industry to consider implementing, but the task force said that the “single most important” recommendation is for the U.S. Congress to pass pending measures to make compliance with electric reliability standards mandatory and enforceable.

The report would give oversight authority to the Federal Energy Regulatory Commission and advises FERC to set and enforce reliability standards even if there is no congressional action. It also calls for the development of a regulator-approved mechanism for funding NERC and regional reliability councils that would free them from dependence on the parties they oversee. The funding mechanism would be based on a surcharge in transmission rates.

“Although this final report presents some new information about the events and circumstances before the start of the blackout and additional detail concerning the cascade stage of the blackout, none of the comments received or additional analyses performed by the task force’s investigators have changed the validity of the conclusions published in the interim report,” the task force said. “This report, however, presents findings concerning additional violations of reliability requirements and institutional and performance deficiencies beyond those identified in the interim report.”

The final report includes a total of 46 recommendations, “but the single most important of them is that the U.S. Congress should enact the reliability provisions in H.R. 6 and S.2095 to make compliance with reliability standards mandatory and enforceable.” The task force said that if “that could be done, many of the other recommended actions could be accomplished readily in the course of implementing the legislation.” H.R. 6 and S.2095 are competing versions of comprehensive energy legislation that remain pending on Capitol Hill.

The task force said that the U.S. Congress should enact reliability legislation “no less stringent” than the provisions now included in the pending comprehensive energy bills, H.R. 6 and S. 2095.

In the absence of such reliability legislation, the task force said that FERC should review its statutory authorities under existing law, and to the maximum extent permitted by those authorities, act to enhance reliability by making compliance with reliability standards enforceable in the U.S.

“In doing so, FERC should consult with state regulators, NERC, and the regional reliability councils to determine whether certain enforcement practices now in use in some parts of the U.S. and Canada might be applied more broadly,” the report said. The task force noted, for example, that in the Western U.S. and Canada, many members of the Western Electricity Coordinating Council (WECC) include clauses in contracts for the purchase of wholesale power that require the parties to comply with reliability standards. In the areas of the U.S. and Canada covered by the Northeast Power Coordinating Council (NPCC), parties found not to be in compliance with NERC and NPCC reliability requirements are subject to escalating degrees of scrutiny by their peers and the public.

“Both of these approaches have had positive effects,” the task force said. “FERC should examine other approaches as well, and work with state regulatory authorities to ensure that any other appropriate actions to make reliability standards enforceable are taken.” Action by FERC “under its existing authorities would not lessen the need for enactment of reliability legislation by the Congress. Many U.S. parties that should be required by law to comply with reliability requirements are not subject to the Commission’s full authorities under the Federal Power Act.”

Meanwhile, the report said that U.S. and Canadian regulatory authorities should work with NERC, the regional councils and the power industry to develop and implement a new funding mechanism for NERC and the regional councils based on a surcharge in transmission rates. The purpose would be to ensure that NERC and the councils are appropriately funded to meet their changing responsibilities without dependence on the parties that they oversee.

NERC’s current $13 million/year budget is funded as part of the dues that transmission owners, generators and other market participants pay to the 10 regional reliability councils, which then fund NERC.

“This arrangement makes NERC subject to the influence of the reliability councils, which are in turn subject to the influence of their control areas and other members,” the task force said. “It also compromises the independence of both NERC and the councils in relation to the entities whose actions they oversee, and makes it difficult for them to act forcefully and objectively to maintain the reliability of the North American bulk power system.”

Funding NERC and the councils through a transmission rate surcharge administered and disbursed under regulatory supervision “would enable the organizations to be more independent of the industry, with little impact on electric bills. The dues that companies pay to the regional councils are passed through to electricity customers today, so the net impacts on customer bills from shifting to a rate surcharge would be minimal.”

Glotfelty said he thinks the shift to such a funding mechanism could be done even in the absence of congressional action on legislation mandating reliability rules. “Utilities currently include their dues in their rates and it would not be a problem from our standpoint to ensure that they’re included in rates without legislation being passed, so it should not be a problem to make that recommendation complete,” he said.

When asked to describe how much influence utilities currently have over NERC and other oversight-related organizations, Glotfelty said that “I think the answer is, we don’t know, but now is not the time to find out. What we need to do is make sure we implement recommendations that assure that there is not improper influence over rules and regulations that NERC is implementing.”

The report notes that implementation of the recommendations offered in the report will involve a substantial increase in NERC’s functions and responsibilities, and require an increase in NERC’s annual budget. “The additional costs, however, would be small in comparison to the cost of a single major blackout.”

Other recommendations included in the report are:

The task force also thinks it makes sense for the DOE and Natural Resources Canada to commission an independent study of the relationships among industry restructuring, competition in power markets and grid reliability “and how those relationships should be managed to best serve the public interest.”

The report also lists three new violations of NERC reliability standards that were not included in the interim report. First, MISO was using non-real-time data to support real-time operations. Second, MISO and PJM, as reliability coordinators, lacked procedures or guidelines between themselves on when and how to coordinate an operating security limit violation observed by one of them in the other’s area due to a contingency near their common boundary. Third, the monitoring equipment provided to FirstEnergy operators was not sufficient to bring the operators’ attention to the deviation on the system.

NERC continues to study the record and may identify additional violations, the report notes.

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