Power Engineering - Blackout analysis reveals major structural problems

CAMBRIDGE, Mass., Dec. 17, 2003 -- The Blackout of August 14th could have been avoided if appropriate corrective steps had been taken, and a number of important reliability safeguards and market design principles have emerged from analysis of the incident, according to a new report by Cambridge Energy Research Associates (CERA).

"The events that caused the blackout to spread are well documented in the task force's report," said Hoff Stauffer, a CERA Senior Consultant specializing in electric transmission. (Interim Report: Causes of the August 14th Blackout in the United States and Canada, available at http://www.electricity.doe.gov.) "Beyond that, some important lessons to be learned are already clear."

According to the CERA report, when the transmission lines into First Energy from the south began to fail, they were carrying about 3000MWs. Because the failing lines could not carry so much power, the flows had to be reduced to avoid losing additional lines and ultimately causing a widespread Blackout.

This could have been accomplished by redispatch, with generation north of the lines (in Michigan to the north and PJM connected to First Energy in the east) being increased, and generation south of the lines reduced. As a last resort, load within First Energy could have been shed. (See redispatch exhibit attached.)

"Unfortunately, this redispatch did not occur, for a variety of reasons explained in the DOE report," Stauffer said.

The reliability lessons relate to both structure and process, according to the CERA report.

All highly interconnected areas, such as Michigan, Ohio, and Indiana, should have a single reliability authority with sufficient information, adequate breadth of view, and the necessary authority to recognize and resolve transmission problems before they get out of control, says CERA. Further, there is clearly a strong case that mandatory national reliability standards should be established and enforced by a federal agency.

PJM and MISO are jointly responsible for reliability in the Midwest, which is a highly interconnected grid. But PJM did not have the information required to see the severity of the problem, and neither PJM nor MISO had the authority to take the direct actions required.

The task force itself concluded that "MISO was hindered because it lacked clear visibility, responsibility, authority, and ability to take the actions needed in this circumstance."

"AEP was able to understand what was happening better than MISO and FirstEnergy, but the communication between the parties was apparently inadequate," said Stauffer. "Perhaps AEP had no idea that MISO and FirstEnergy had not recognized the problems. Perhaps FirstEnergy operators did not adequately understand what AEP was saying, since the FirstEnergy alarms were not operating."

"Neither PJM nor MISO had the breadth of vision to see the enormity of the problem," said Stauffer. "If MISO had recognized what AEP had recognized, it might have initiated the redispatch that would have avoided the blackout."

The important market design lessons involve both how the market should be designed ultimately and what should be done in the interim to prevent such an enormous blackout from recurring. These lessons include:

* MISO is not currently functioning like the longer-operating independent system operators (ISOs) in the east, such as PJM, New York ISO and ISO New England. PJM has effective direct control over generator outputs through its transmission control centers, enabling it to re-dispatch quickly when a problem occurs. MISO does not currently have direct control over generation, although it plans to in the future.

* MISO currently manages a system of "flow gates" and transmission loading relief (TLR) requests to avoid overloading the transmission system. MISO schedules transmission flows such that these flow gates are not overloaded, and then requests TLRs to reduce flows on certain lines when a problem occurs. The TLR system is not automatic and takes precious time. A PJM-type market design appears to be the best approach, and the Midwest has plans to implement such a market design. But until this happens, if the TLR process is the only means MISO has to ensure reliability, then the flow gates should be set more conservatively so that the cumbersome TLR process has time to solve a problem.

* Merchant generators have no financial incentives to comply with MISO re-dispatch requests. This problem does not exist in PJM, which uses locational marginal prices (LMPs). In PJM, when a transmission constraint occurs that requires re-dispatch, generators that need to reduce output will be earning low LMPs and will be pleased to reduce generation to avoid losing money. Conversely, generators that need to increase output will do so in order to earn very high LMPs. Further, PJM has a "no harm" principle, under which any economic harm to generators resulting from an emergency situation will be equitably redressed when the situation is over.

"Some of the lessons discussed above have important implications for the design of retail customer choice programs," said Stauffer. On this basis, it appears that retail choice customers should be required to provide for:

* Generation capacity in excess of their peak load by the amount of a specified reserve margin. This capacity also should have a deliverability requirement, such that it is either in the customer's service territory or there is adequate transmission available to bring it in when needed. Otherwise, there might not be enough capacity available within a region to satisfy all the loads reliably.

* Customers who purchase from competitive retailers should have an obligation to purchase the reactive power consumed by their loads and/or by the long-distance transmission from distant generators. (When transmission lines get heavily loaded, they consume reactive power, and doubling the flow requires four times the reactive power.) This would place responsibility for procuring reactive power on those that consume it.

The sequence of failures that led to the blackout has been detailed in the reports issued to date by the joint U.S.-Canadian task force created to investigate the incident. These reports describe problems in Ohio beginning as early as 1:31 pm Eastern Daylight Time (EDT) with the trip of First Energy's 550 megawatt (MW) East Lake generating unit in the Cleveland area.

The task force has determined that the key initiating events did not begin until after 3:05 p.m. EDT, however, when a transmission line in northern Ohio failed and electricity flows were not reduced in compensation. This was followed by the failure of another line in eastern Ohio at 3:32 p.m. EDT. Again, flows were not reduced, despite the existence of adequate capacity for re-routing the electricity on other nearby lines.

When the transmission lines began to fail, the alarms in First Energy's control room should have gone off, but they were not operating, for reason that remain unknown at this time. Thus, even though both First Energy and its reliability authority, MISO, had access to data that would have revealed the problem, neither recognized it or attempted any re-dispatch.

The utility to the south of FirstEnergy - American Electric Power (AEP) - saw part of the problem and issued a transmission loading relief (TLR) request to its authority, PJM, at about 3:38 pm. But, according to the task force's report, a delay occurred when security coordinators asked why AEP was requesting such a large TLR (350 MW). Before the TLR could be implemented, all the major south-to-north lines on the eastern side of Ohio failed.

AEP had identified the problem and was trying to solve it, but, according to the official report, "...they still found no practical way to mitigate these overloads across the utility and reliability coordinator boundaries."

"Being tied to a very large power grid is both good and bad," concludes Stauffer. "The good part is that more generators and loads are spread over a massive power grid, providing more possibilities that a sudden loss of generation or increase in load in one place can be satisfied by the inertia of the grid, rather than destabilizing an individual (much smaller) geographic area."

Another benefit is that more economic transactions can be made by moving available, low-cost energy to places where energy prices are much higher.

"A clear negative is that any one geographic area is vulnerable to problems in other areas," Stauffer adds. "These problems can be random, and they can be compounded by performance and coordination problems in other geographies, as was the case in the recent blackout."

Overall, the good outweighs the bad, says CERA. The focus needs to be on taking full advantage of the good parts while minimizing the downside risks of the bad.

"There are some very important lessons to be learned from the blackout," says Stauffer. "The immediate need is to refine these and act on them expeditiously."

CERA's Electric Transmission Service conducts extensive, on-going research and analysis on technical, policy, regulatory, and marketing issues concerning the North American power grid. The Blackout analysis is one such topic which has received considerable attention recently since the occurrence in August, 2003. CERA has also undertaken a comprehensive and detailed analysis of the adequacy of transmission grid in its multi-client study: "Grounded in Reality: Bottlenecks and Investment Needs of the North American Transmission System." For additional information please contact: Gilbert M. Rodgers, Co-Leader, CERA Transmission Service, 617-866-5365, grodgers@cera.com.

Cambridge Energy Research Associates is an advisor to major North American and international companies, financial institutions and organizations, delivering strategic knowledge and independent analysis on energy markets, geopolitics, industry trends and strategy. CERA is headquartered in Cambridge, Mass., and has offices in Beijing, Calgary, Houston, Mexico City, Moscow, Oakland, Oslo, Paris, Sao Paolo, and Washington, D.C.

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