EPRI Issues Updated “Red Book”

The Electric Power Research Institute (EPRI) unveiled an updated and expanded edition of its landmark guidebook EPRI AC Transmission Line Reference Book: 200 kV and Above, Third Edition, which is widely known as the “Red Book,” the industry standard on high-voltage line design.

The latest Red Book modernizes theories and techniques for transmission line design and operations, and EPRI offers Red Book-based training to system operators on a regional or company-specific basis. The Red Book is available to members and non-members at $5,000 per hardcover copy including a CD-ROM of stand-alone calculation modules.

“This edition of the Red Book includes a greater global scope, is designed to be much more effective as a training tool and includes a significant amount of institutional learning and memory that would otherwise be lost as a generation of transmission experts begins to enter retirement,” said Andrew Philips, EPRI program manager for transmission.

The Red Book was first published in 1975 under the title Transmission Line Reference Book, 345kV and Above (EL-2500). It featured a red cover, and the text quickly became known simply as the Red Book. Over the past three decades, it has been in use daily throughout the global power industry.

The Fantastic Four of Transmission Development

Arizona Public Service Company, PacifiCorp, National Grid and the Wyoming Infrastructure Authority have entered into an agreement to work together on preliminary development of new high-voltage transmission lines for the West.

The agreement builds on PacifiCorp’s May 30, 2007, announcement the company would construct, by 2014, more than 1,200 miles of new 500-kV transmission lines. One segment of that proposed transmission project, a southern route line, from eastern Wyoming into Utah and on to the desert southwest, has aspects in common with a project proposed in October 2005 by APS.

In the agreement, the four parties agree to work together on initial activities during the next six months to co-develop these projects, with a decision on next steps to be made in 2008.

UTC to Utilities: All Aboard! CIP Compliance Now!

The Utilities Telecom Council (UTC) recently released this opinion statement:

Many utilities have taken steps to comply with new North American Electric Reliability Corporation (NERC) Critical Infrastructure Protection (CIP) standards aimed at protecting the electric power grid from cyber attack, but few utilities are CIP-compliant, and there is much work to be done. The eight proposed CIP Reliability Standards, submitted by NERC to the Federal Energy Regulatory Commission (FERC) in 2006, will be adopted as federal regulations sometime in the next several months. However, a very tight compliance timeline is, and likely will remain, in place. Utilities that do not meet audit requirements will face stiff penalties for non-compliance when audits begin in 2009.

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Entities responsible for NERC compliance face a number of obstacles in their efforts to address cyber security: manpower is limited and utilities and transmission companies must prioritize work that keeps electricity flowing. But, utilities have no choice but to establish compliance programs now if they are going to be ready for NERC audits.

“We are encouraging our members, and in fact all utilities, not to delay preparing for CIP compliance,” said William R. Moroney, president and CEO of the Utilities Telecom Council. “We’ve heard from our members how demanding it can be to coordinate all the necessary steps for compliance. Yet NERC compliance is essential to not only avoid potential hefty fines, but also to secure current and next-generation infrastructure from potentially disastrous cyber attack.” The Utilities Telecom Council (UTC) has produced a report, “NERC Cyber Standards: Ten Steps to Compliance,” to help utilities navigate through this process.

LiveData Assists Georgia Power

LiveData and Oracle have deployed the companies’ SCADA integration solution for distribution outage management at Georgia Power Company (GPC). The largest electric utility in Georgia, GPC has improved its response to outages and other distribution issues using Oracle Utilities Outage Management SCADA and the LiveData ICCP Server.

GPC’s supervisory control and data acquisition (SCADA) system gathers information from remote sensors, learning the status of devices on the power network. The LiveData ICCP Server interfaces data to Oracle Utilities’ network management adapter. Once SCADA data reaches Oracle Utilities Outage Management SCADA, the Oracle Utilities network management system integrates and analyzes it to identify power distribution issues.

The Inter-Control Center Protocol (ICCP) is an interconnection standard between SCADA and energy management systems (EMS). Oracle Utilities brings its expertise of analyzing SCADA data for distribution network outages, by interfacing to LiveData’s ICCP Server. LiveData provides the ICCP protocol product and protocol expertise for ICCP data exchange with SCADA and EMS systems.

“It removes a layer of complexity. This helps improve reliability and customer satisfaction,” said Duncan Livsey, senior applications analyst at Georgia Power.

Neptune Project Ahead of Schedule

In July 2005, Siemens was awarded the contract to build a Sayreville, N.J.-Long Island, N.Y. interconnection by Neptune Regional Transmission System LLC of Fairfield, Connecticut. After commissioning, Neptune RTS, owner and operator of the transmission system, will place the power link at the disposal of the local utility, Long Island Power Authority (LIPA), allowing them access to PJM.

Starting at the end of June 2007, 660 MW at a DC voltage of 500 kV can flow via the HVDC submarine cable interconnection. The project was constructed by a consortium of Siemens and Prysmian Cables and Systems of Milan, Italy. The total equipment and construction contract value was approximately $400 million. Siemens, as the consortium manager, designed, manufactured, supplied, installed, and commissioned the two HVDC converter stations on a turnkey basis. The Siemens equipment included converter valves, converter transformers, smoothing reactors, high voltage switchgear as well as communication and control equipment. Siemens was also responsible for the local civil construction work scope including valve halls and operations buildings. The consortium partner, Prysmian, supplied and installed a total of 65 miles of submarine and subterranean cable.

Siemens will provide all the operation and maintenance services required for the first five years of the link’s operation.


The City of Anaheim Public Utilities has completed the production deployment of the Advanced Control Systems (ACS) PRISM real-time outage management system (OMS). In addition to OMS, Anaheim has deployed ACS solutions for SCADA, substation and feeder automation, interactive voice response for crew call out, and enterprise business intelligence, including real-time tracking and reporting of IEEE 1366 reliability indices.

Eye on Europe: EU Commission Happy about Surveillance

EU energy commissioner Andris Piebalgs welcomed the positive outcome of the electricity suppliers surveillance system deployed this summer being ready to act in the event of any major supply disruptions.

Although the system has been running for three years, this has been the first time that the Commission has given those responsible for the system the possibility of bringing together all those member states affected by the problem and to take steps to ensure it did not recur.

High temperature forecasts and low resources on hydro energy in some member states made this season the object of a special vigilance. This summer, the system followed closely a number of supply interruptions – like the one in Barcelona on July 23 and the ones in the UK in and around Gloucestershire at the end of July following flooding – but those did not require a response at the European level. Officials managing the system have also been in close contact with Greek authorities to evaluate the impact of the forest fires on the electricity system.

The system has not been really tested under “crisis conditions” as defined by the Commission, the EU reported. The last time that there was a major problem (arising in Germany in November 2006 when a large part of Europe lost its power supply), the then existing reporting system of the transmission system operators (TSOs) did not appear to be very robust. For this reason, the subject of better coordination between TSOs was addressed in the third internal market package (adopted by the Commission on Sept. 19, 2007).

FERC Report Marks Growth of Demand Response Efforts

Demand response and advanced metering programs have grown significantly over the past year, according to a new Federal Energy Regulatory Commission (FERC) report that charts progress in the number of demand response programs, the number of states introducing opportunities for demand response and the key role that demand response is playing in organized wholesale power markets.

The report, “Assessment of Demand Response and Advanced Metering 2007,” notes major demand response developments in wholesale markets, including the use of demand resources in forward capacity markets and ancillary services markets, and the development of new reliability-based demand response programs. The report estimates that demand response in 2006 lowered the consumption of electricity by 1.4 percent to 4.1 percent during periods of peak demand on the systems.

“Demand response is playing a more important role in U.S. electricity markets,” FERC chairman Joseph T. Kelliher said. “Last year, demand response played a key role during a summer when we set record electricity demand levels in eight regions of the country. But we need to make more progress.”

The commission continues to assess demand response as it relates to ensuring competitive wholesale markets and reliability of grid operations, Kelliher added. “We have looked at the role of demand response in several rulemakings, including transmission planning and reliability standards. We also have convened two technical conferences and are continuing collaborative efforts with state regulators on demand response. I commend the leadership of commissioner Jon Wellinghoff in this important collaborative process.”

Commissioner Wellinghoff is leading FERC’s efforts in the collaborative dialogue on demand response with the National Association of Regulatory Utility Commissioners.

“The findings of the staff report signal that there has been a change in the national demand response dialogue from should we do it, to how we do it,” Wellinghoff said. “This report should provide real value to regulators, policy makers, utilities, and consumers in this rapidly growing and ever-important electric resource sector.”

ITC, AEP Study Outlines Transmission Project

ITC Holdings Corp., in collaboration with American Electric Power (AEP), has released the findings of a joint study evaluating the feasibility and benefits of building a new 765-kilovolt (kV) transmission network across Michigan’s southern Lower Peninsula into Ohio. The study, originally undertaken to analyze transmission needs in Michigan, also details some of the regional benefits such an extra-high-voltage electric infrastructure could provide to the Midwest.

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The proposed 700-mile network would connect to existing AEP high-voltage systems in the southwest corner of Michigan and in Ohio and establish a regional transmission corridor capable of improving electric reliability, relieving power congestion, enhancing market access to the grid, and aiding in more efficient distribution of current generation, said the companies. The network would run through the service territories of ITC subsidiaries International Transmission Co. (ITCTransmission) and Michigan Electric Transmission Co. LLC (METC) and branch off of AEP’s existing 765-kV network in northern Ohio.

Specific findings in the report indicate that:

  • The proposed 765-kV network would free up capacity on the existing 345-kV system in Michigan’s Lower Peninsula and accommodate transfer of as much as 5,000 additional megawatts (MW) of electricity through the region.
  • The project would decrease active power losses during peak conditions by 250 MW.
  • A robust alternating current (AC) 765-kV transmission grid would improve reliability and capacity and magnify the benefits of all other solutions – including new generation – by integrating these solutions and Michigan into a powerful regional network of resources. The scale and capacity of this network would provide Michigan with a self-healing safety net that ensures one resource can instantly compensate for the absence of another in times of need.

AEP and ITC are proposing that the existing 765-kV transmission system that extends into the southwest corner of the Lower Peninsula of Michigan be expanded east across Michigan and south down to the existing 765-kV infrastructure in Ohio. The project will consist of three segments comprising approximately 700 miles of transmission infrastructure, roughly 420 miles in Michigan and 280 in Ohio. If built as proposed, the project is estimated to cost $2.6 billion and take approximately eight years to complete.

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