New Initiative to Explore Smarter Electric Grid for Illinois

A new public-private collaboration is exploring how smart grid technology may bring the people of Illinois more reliable electric service and a cleaner environment, while holding down costs of electric services. The Illinois Smart Grid Initiative is funded by Illinois native Bob Galvin’s Galvin Electricity Initiative and led by the Center for Neighborhood Technology.

Chicago Mayor Richard J. Daley and former U.S. Speaker of the House Dennis Hastert will serve as honorary co-chairs for the effort. The Smart Grid Initiative is a voluntary group of state and local government, consumer, business, environmental, and utility stakeholders that will work together to examine how Illinois consumers can benefit from comprehensive grid modernization. The initiative comes at a critical time for Illinois’ electric power industry, which faces growing peak demand, soaring fossil fuel costs and rising concerns over carbon emissions, all of which threaten to significantly increase electricity costs.

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Initial organizations demonstrating interest in this initiative include consumer groups, environmental groups, business organizations and energy suppliers. A series of stakeholder meetings will be held in the coming months to engage policymakers and other influential leaders in the state in a discussion of critical grid issues, opportunities, and costs, and to develop policies to improve the power system’s performance.

“Through this initiative, Illinois has the opportunity to become a leader in advancing state policies to create an electric grid for the 21st century, and to have more reliable, efficient, secure and greener electricity,” said Bob Galvin, founder of the Galvin Electricity Initiative and retired CEO and chairman of Motorola Inc. “We are proud of this partnership of private and public stakeholders and look forward to it becoming the model for bringing quality power to states around the country.”

To reach and engage people in Illinois, a website ( will be launched soon for the initiative to provide consumers with updates about its progress, energy resources and meetings.

NERC Enforces Compliance

The North American Electric Reliability Corporation (NERC) has submitted the first set of violation notices in the United States to the Federal Energy Regulatory Commission (FERC) for approval under Section 215 of the Federal Power Act.

These notices document which reliability standards were violated and the actions taken by the companies involved to assure future compliance and improve reliability. NERC reliability standards are designed to ensure the right practices are in place so the likelihood and severity of future bulk power system disturbances are substantially reduced.

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This initial set of notices includes a number of violations, the majority of which are documentation-related and do not include a financial penalty. The total value of financial penalties assessed equals $255,000. These violations are already being addressed by the companies involved, who are required to take immediate corrective action in addition to any financial penalties.

The financial penalties are related to violations of NERC’s FAC-003-1 standard titled “Vegetation Management.” Proper vegetation management within transmission rights-of-way is one of NERC’s primary reliability concerns. The companies involved in the recent notices are taking steps to resolve vegetation management violations and improve bulk power system reliability.

“The most important result from these notices is that reliability is being improved across North America due to proactive efforts to prevent future system disturbances,” said Rick Sergel, NERC president and CEO. “It’s often said that the first step to fixing a problem is admitting that a problem exists, and that’s what these companies have done—they have stepped up to the plate and put the measures in place to improve grid reliability.

“Generally we are seeing a very positive response to the “˜new era’ of mandatory compliance enforcement,” continued Sergel. “In fact, more than half of the 1,400 violations reported to NERC after June 18 were self-reported, meaning that bulk power system users, owners, and operators voluntarily disclosed an issue and proposed a way to address it. This is a strong indication that the mandatory enforcement program put in place through the formation of the international Electric Reliability Organization, NERC is driving a culture of compliance, but more importantly reinforcing reliability standards, throughout the electricity industry.”

Details on violation notices can be found at:

Brattle Group: Dynamic Pricing Can Reduce U.S. Peak Demand

The Brattle Group has determined that dynamic pricing can play a substantial role in meeting the demand response goals of various utilities, states and regional transmission organizations in the United States.

This conclusion is based on a discussion paper published by The Brattle Group that summarizes results from the latest 14 experiments with dynamic pricing around the country. Brattle’s analysis of the experiments found that, on average, customers respond to higher prices by lowering usage. The magnitude of price response depends on several factors, including the magnitude of the price increase, the presence of central air conditioning, and the availability of enabling technologies such as two-way communicating thermostats and gateway systems.

For the average customer, time-of-use rates are likely to induce a drop in peak usage of under 5 percent while critical peak pricing tariffs induce a drop of around 10 percent to 25 percent. Customers with central air conditioning are likely to display responses in the 15 percent to 20 percent range while those with enabling technologies in the 25 percent to 45 percent range.

Ahmad Faruqui, a principal of The Brattle Group, presented these findings at the recent DR-Expo in Santa Clara, Calif. According to Dr. Faruqui, “The potential impact of dynamic pricing varies regionally, from 5 percent in the West to 8 percent in the South. By the year 2030, dynamic pricing and other forms of demand response can reduce peak demand in the U.S. as a whole by 11 percent.”

The discussion paper, “The Power of Experimentation: New Evidence on Residential Demand Response,” can be found at

Alabama Power to Install 3M High-Capacity ACCR Conductor

Alabama Power Company plans to install 3M’s high-capacity Aluminum Conductor Composite Reinforced (ACCR) transmission conductor to upgrade a key line at its Miller Steam Plant, according to Tim Koenig, head of 3M’s High Capacity Conductor Program.

Alabama Power is a subsidiary of Southern Company, whose utilities also provide power and other services in Georgia, Mississippi and the Florida panhandle. The Miller Plant is located in Jefferson County, Ala., approximately 25 miles northwest of Birmingham.

3M ACCR can carry more than twice the current of conventional steel-core conductors of the same diameter, generally with no new tower construction or rebuilding because of its relatively light weight, low sag and high strength. Western Area Power Administration, Xcel Energy, Arizona Public Service, and Shanghai Electric Power in China are among the major utilities that have deployed the conductor to alleviate or preclude peak-demand bottlenecks in major metropolitan areas.

Alabama Power’s 1.7-mile upgrade, utilizing 3M ACCR 1033 kcmil 54/19 Curlew, will boost transmission capacity on a line that goes through and loops around the Miller Steam Plant. The upgrade is part of Alabama Power’s ongoing, multibillion-dollar environmental initiative, designed to reduce emissions from the company’s power plants, while continuing to meet growing power demand.

The population of greater Birmingham is now estimated at 1.08 million, making it the largest metropolitan area in the state. The new 230-kV line will be rated to carry up to 2,000 amps and is expected to peak at a temperature of 200 degrees Celsius.

Said Howard Samms, a senior engineer at Alabama Power, “The existing line crosses below three 500-kV lines and above one 230-kV line and is supported on five existing lattice steel structures. The 3M conductor allowed us to obtain the required capacity, while utilizing the existing structures and maintaining or improving the existing clearances to ground and other obstacles. As a result, significant savings were achieved in both time and cost by eliminating the need for the design, supply and construction of new towers.”

3M ACCR was developed with the support of the U.S. Department of Energy, which tested the conductor at its Oak Ridge National Laboratory (ORNL) in Tennessee, and with early contributions by the Defense Advanced Research Projects Agency.


Baltimore Gas and Electric Company (BGE), a subsidiary of Constellation Energy, has selected Cooper Power Systems to provide a system for peak demand reduction designed for BGE’s residential customers. Cooper expects the project will represent $42 million in revenue over the period 2008-2011—and when expanded to full capacity, it will provide more than 600 megawatts of clean energy capacity by 2011.

Aclara Selected for PG&E’s 2008 Smart Meter Program

Pacific Gas and Electric Company (PG&E) has selected the STAR Network system from Aclara RF Systems Inc. (formerly Hexagram), a subsidiary of ESCO Technologies Inc., to provide additional electric advanced metering infrastructure (AMI) products for PG&E’s SmartMeter Program.

PG&E began evaluating Aclara’s RF electric solution in June 2007 with a 2,000-unit field trial intended to demonstrate and validate the capabilities of Aclara’s electric RF fixed network. The successful performance of this technology throughout the field trial was a significant factor in PG&E’s decision to expand the product’s deployment.

PG&E has ordered 88,000 Aclara RF electric devices to be installed in the Central Valley region of northern California, which extends from Modesto to Sacramento. These units will include a ZigBee connector as well as an interface to a connect/disconnect function integrated in the meter. PG&E has indicated it is their intent to order a significant quantity of Aclara RF electric AMI devices throughout 2008, in addition to the nearly 400,000 TWACS power-line based electric AMI devices being installed in the Bakersfield and Vacaville areas.

Colorado Springs, Cellnet+Hunt Reach Metering Project Milestone

Colorado Springs Utilities, a community-owned utility serving customers in Colorado Springs and the surrounding area, has surpassed 280,000 endpoints deployed in its electric, gas, water and wastewater advanced metering project that started in 2005. When the rollout is complete in 2010, Colorado Springs Utilities will be using the utility-owned RF mesh network to read more than 528,000 electric, gas, and water meters, maintaining its status as the largest combined, four-service advanced metering project in the United States.

Colorado Springs Utilities anticipates that, when fully deployed, the Cellnet+Hunt system will save the utility more than $6 million dollars per year in hard operating cost, not including the operational benefits the utility expects to achieve through the fixed network deployment.

“The work on this project to date has forged a hard won partnership between Colorado Springs Utilities and Cellnet+Hunt,” said Gina McCurley, Colorado Springs Utilities project manager. “As we pass the project mid-point, Colorado Springs Utilities is already gaining significant customer value from this project.”


Rank and file: SAP ranked first and Excelergy second in CIS/billing vendor name recognition in a new survey of European utilities and energy marketers. The survey results were part of a new study published by UtiliPoint International Inc.

The European study follows a North American study published by UtiliPoint last year in which billing and customer care vendors serving deregulated markets were ranked on the basis of reputation, industry focus, market share, channels partners, customer satisfaction, functionality, integration and product support.

“Escalating competition in European retail power and gas markets has changed the business model at many energy-marketing companies,” said Rudolf Das, vice president–international at Excelergy. “Retail margins are thin and profitability requires near perfect execution in the back office. This means energy providers have to acquire, service, and bill customers as inexpensively as possible without sacrificing accuracy or flexibility.”

Utility Board Considers Salary Freeze

Kissimmee Utility Authority’s board of directors discussed a staff suggestion to implement an employee salary freeze for the upcoming budget year. The move would achieve an estimated savings of $661,000.

The plan also suggested the transfer of the achieved savings to the city of Kissimmee to help preserve jobs of city employees. The Kissimmee City Commission recently approved a layoff plan for its employees.

The suggestion was discussed at length by the utility board, but no action was taken.

“As KUA prepares its budget for 2008-09, we are taking a hard look at expenses,” said Jim Welsh, KUA president and general manager. “The utility is evaluating the need for new positions and is looking to decrease spending in several areas, including utility advertising and community sponsorships.”

Founded in 1901, KUA ( is Florida’s sixth largest community-owned utility providing electric and telecommunication services to 170,000 residents in five Central Florida counties.


“ABB experienced a very good start in 2008 across all businesses and regions. Demand from utilities and most of our major industrial markets remained strong around the world, especially in emerging economies.”

— Michel Demaré, ABB’s chief executive officer and chief financial officer, discussing the company’s first-quarter net income of $1 billion, an increase of 87 percent compared to the same quarter in 2007.


SensorTran has joined the GridWise Alliance, a leading consortium focused on transforming the nation’s electric grid. SensorTran is the first distributed temperature sensing (DTS) provider to join more than 50 companies—including Cisco, GE, IBM and SAP—with the collective objective of leveraging innovative new technologies to fulfill the smart grid vision in the U.S.

Lake Country Power Completes AMI Deployment

Lake Country Power of Grand Rapids, Minn., has successfully deployed a full two-way automated metering infrastructure (AMI) to its entire service territory covering more than 10,000 square miles in northern Minnesota.

The Cannon AMI system by Cooper Power Systems gives Lake Country the ability to read meters on demand, improve cash flow, reduce customer complaints, decrease issue resolution time, verify outages and restoration real time, and monitor substation equipment.

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“We wanted a system that could be installed in all 39 of our substations, with the capability to handle more than 60,000 meter reads and remotely monitor our substation equipment,” Rick Lemonds, Lake Country Power general manager said. “Our AMI system has already made positive service impacts, by providing the right employees with the right information when requested. This provides our members with data to support answers to their questions.”

Lake Country Power has noticed time savings in solving customer issues through the ability to profile energy use and remotely read meters from the office. “In the past we would send a technician on site to check on most high-bill issues,” Lemonds said. “Now we handle many of these directly from the office, greatly reducing our time and expense to resolve these customer inquiries.”

The AMI system integrates with Lake Country Power’s existing billing and outage management software, allowing for the automatic generation of monthly billing statements and verification of outage events and restoration. Lake Country Power anticipates significant savings using the system to verify load management commands sent to its load control receivers.

“Often with projects of this size the functionality gets reduced as the project rolls out,” Lemonds said. “But with our system, the reality is living up to the vision. We now have the ability to verify load management control commands, remotely read meters, verify outages, assist with the restoration of power, and perform remote power quality monitoring at the distribution and substation levels. We had an aggressive deployment schedule and we were able to achieve the roll out on schedule. We look forward to what else our two-way network will be able to provide for in the future.”

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DistribuTECH 2007 Opens Call for Papers

DistribuTECH 2006 visited beautiful Tampa, on Florida’s sunny West coast from Feb. 7-9, 2006. While there, more than 4,000 utility engineers, executives, aggregators, consultants, researchers and other industry insiders gathered to debate automation and control systems, equipment, power delivery, T&D systems and water technology. DistribuTECH 2007 promises to be just as successful when the conference returns to the West Coast for a show in San Diego, Feb. 4-6, 2007.

In preparation for DistribuTECH 2007, the call for papers has gone out to interested industry experts. Those interested in submitting an abstract for consideration can do so using the online form at

Abstracts should identify an issue, technology or project that is relevant and informative to the power transmission and distribution industry. Authors should develop a 200- to 400-word, one-page synopsis of the key points to be addressed in the proposed presentation. (The online submission form will accept up to 400 words.) Authors can also choose to present a manuscript or be a part of a panel discussion.

Once the abstract has been submitted, an automatic e-mail response will be sent to the author to confirm that DistribuTECH conference management has received it. The deadline for abstracts is June 26, 2006. The DistribuTECH 2007 Program Committee will review all abstracts submitted by the June 26 deadline. All abstracts will be evaluated on the strength of the abstract submitted, including content matter, market trends and relevance of the material. All primary contacts will be notified in writing no later than Sept. 1, 2006, as to whether or not their proposed DistribuTECH abstract has been selected.

Questions about the conference or about submitting an abstract can be directed by e-mail to

UTC Releases Report on WiFi and WiMAX for Utilities

The United Telecom Council (UTC) released a new report in March titled, “WiFi and WiMAX for Utilities: A Primer Update 2006,” exploring ways in which the energy and related industries are beginning to use these technologies for primary and backup communications applications. The themes of integration, mobility, low cost and interoperability emerge as excellent reasons for utilities to test the waters of WLAN (wireless local area network) and WMAN (wireless metropolitan area network) technologies, and many are expected to incorporate this technology in the future, according to the report.

The research report highlights several key areas, including:

  • WiFi (wireless fidelity) and WiMAX (Worldwide Interoperability for Microwave Access) technical basics,
  • Technology drivers and limitations,
  • WiFi as a low-cost community broadband option, and
  • Utility deployments to date and potential usages.

While WiFi provides local network access without the fuss of cords and wires, WiMAX can extend that access farther, in both distance and points of access. The UTC report indicates that utilities have started to “test the waters” with both WiFi and WiMAX but that deployment of those technologies hasn’t been nearly as widespread as what the general public has embraced in this area. However, UTC predicts “the emergence of interoperable devices with chipsets handling WiFi, WiMAX and 3G wireless communications.”

The UTC report gives a numbers of areas where utilities may put fingers into the WiFi pie. One is for direct consumer access, a municipal WiFi, of sorts. Another is to smooth government communication and emergency infrastructure. (Examples of cities implementing or planning WiFi/WiMAX public access are listed in the report.) Additionally, the cheap cost and no need for infrastructure offered by WiMAX technologies may usurp other options when entering rural or third-world markets, according to the UTC report.

The UTC report lists a number of reasons utilities are “good candidates” for WiFi/WiMAX deployment, including broadband capacity, “last-feet” access (inside a consumer’s home or business), existing infrastructure, mobile workforce needs and disaster recovery (among others).

WiFi and WiMAX also will impact technology platforms that utilities utilize. Currently, the UTC sees WiFi and WiMAX usage among utilities mainly to band-aid broadband gaps. However, the report contends that “regardless of the role that they play in the future of broadband wireless technologies, and even if WiFi does not evolve as a full replacement for what was once called 3G networking, WiFi/WiMAX can be expected to play the role of an intermediate technology at the very minimum.”

Those interested in ordering the report can do so at

NERC Files ERO Application in the U.S., Canada

The North American Electric Reliability Council (NERC) filed its application to become the Electric Reliability Organization (ERO) with the U.S. Federal Energy Regulatory Commission (FERC), in compliance with the Commission’s “Final Rules Concerning Certification of the Electric Reliability Organization and Procedures for the Establishment, Approval, and Enforcement of Reliability Standards.”

FERC established rules governing the formation and approval of an ERO in accordance with the reliability provisions of the Energy Policy Act of 2005. Concurrently with its FERC application, NERC made filings seeking comparable recognition from government authorities in Canada, including the provinces of British Columbia, Alberta, Saskatchewan, Manitoba, Ontario, Quebec, New Brunswick, and Nova Scotia, and the National Energy Board.

Once NERC gains recognition as the ERO from the United States and in Canada, NERC will have the authority to develop and enforce reliability standards for the bulk power system in both countries. NERC is working to receive all necessary approvals from U.S. and Canadian authorities later this summer so that it can begin operations as the ERO on January 1, 2007.

“NERC’s ERO application is the culmination of years of hard work by NERC staff and electric industry stakeholders to establish a self-regulatory organization with the capability and the authority to develop and enforce compliance with reliability standards,” said Rick Sergel, NERC president and CEO. “We look forward to working with governmental authorities in the United States and Canada to become recognized as the ERO in both countries.”

“Approval of NERC’s applications will result in the formation of an independent, truly international reliability organization that will operate for the benefit of all North Americans,” stated NERC Chairman Richard Drouin. “We commit to do everything in our power to ensure that NERC not only meets but exceeds the high expectations placed upon it by our governments, the industry, and the public.”

The ERO application provides the documentation necessary to demonstrate NERC meets all statutory and regulatory requirements and demonstrates NERC’s competence to be a strong and effective ERO. The application includes a comprehensive set of documents defining the structure, governance, bylaws, rules of procedure, and operational procedures of the ERO, and clearly defines the authorities and responsibilities of the ERO, regional entities, and the bulk power system owners, operators, and users that are within the ERO’s jurisdiction for reliability purposes.

The application contains a formal request for certification, a statement of NERC’s qualifications to become the ERO, the certificate of incorporation, regional delegation agreements, and a transition plan. NERC submitted its existing reliability standards for approval under a separate filing concurrent with the applications.

While its ERO applications are pending, NERC’s existing reliability standards will remain in place. During this transition period, NERC will continue to monitor and report on industry compliance with its reliability standards, develop new standards, improve existing reliability programs and develop new ones in accordance with its expected reliability responsibilities as the ERO.

ABB Wins $65 Million Substation Upgrade Order

ABB has won a $65 million order to upgrade an existing 230-kV/69-kV substation, build a new 230/69-kV gas insulated switchgear substation, install a new transmission line between them and convert several miles of existing overhead power lines to underground cable for Anaheim Public Utilities in Anaheim, Calif.

“Our technology will help to ensure reliable power supply to the city,” said Samir Brikho, head of ABB’s Power Systems division. “We are well positioned to take on projects of this scope, where the customer needs a complete package of technology and project management expertise.”

ABB will provide all engineering, equipment and material procurement, construction and commissioning on the project, which is slated for completion in just under two years.

“The Lewis 230-kV Extension Project is the largest individual undertaking by our electric utility,” said Marcie Edwards, general manager for Anaheim Public Utilities. “The completed project will provide the city with a much-improved, reliable source of power along with aesthetic improvement of the electric facilities in and around the substations.”

Sierra Pacific Power to Update Network Model

JCMB Technology Inc., a provider of software and services to electric, gas and water utilities, has been contracted by Sierra Pacific Power Company (SPPC) to consolidate, capture and collect data to update its existing distribution network data model and ultimately provide field operators with maps that accurately reflect actual field conditions of the outlying districts within the SPPC service territory.

Under this contract, JCMB’s mandate is to collect field data and perform data maintenance. This will bridge the gap between what is currently mapped and what is required to run their operational system more effectively. JCMB will provide on-site data mapping technicians to capture and consolidate missing facilities found on paper, digital and strip map sources. As well, they will go into the field with SPPC field crew members and verify the actual operable devices that exist in the field vs. those mapped. JCMB technicians will reconcile discrepancies found by making the necessary changes directly in the Adele software, so that they reflect the surveyed field information.

The technicians will be working with Bluetooth-linked submeter GPS units and Tablet PCs that will provide the accuracy required for this project. Technicians will collect the location and attributes of devices, risers and structures.

SDG&E Updates Plan for Advanced Meters

San Diego Gas & Electric (SDG&E) filed an updated proposal for the installation of advanced meters for all of its customers by 2010. The updated plan calls for the replacement of SDG&E’s electric customer meters with smart meters that will allow two-way communication between the utility and its customers. SDG&E also is proposing to tie its gas meters into the system. If approved, meter installation will begin in mid-2008 and be completed by 2010.

The smart meters are expected to provide SDG&E customers with numerous benefits including improved customer service, more real-time information on energy use and faster outage restoration.

The new meters, along with advanced communication capabilities, will allow SDG&E to move toward operating its electrical system and providing utility services at much higher levels of automation and reliability than today, according to the utility.

“These meters lay a foundation that provides benefits today and prepares SDG&E and its customers for the technologies of tomorrow,” said Anne S. Smith, senior vice president, customer services, for SDG&E.

The updated plan, which replaces a proposal filed with the California Public Utilities Commission (CPUC) in March 2005, supports California’s energy policy goals. Those goals call for expanded use of energy-efficiency and demand-response initiatives. The information provided by smart meters will enable customers to customize their energy usage to match savings opportunities by shifting electricity usage away from times of peak consumption.

“We believe our updated plan will provide our customers with added advantages over the original proposal,” Smith said.

SDG&E plans an extensive outreach campaign, including the launch of a comprehensive customer-education effort, direct mail, e-mail, Web-based communication and public presentations to inform customers about the program. The outreach will focus on explaining the meter’s communication system and its benefits, as well as how to take best advantage of the meter’s capabilities. SDG&E also will hold community forums to gather customer feedback.

Before drafting its current plan, SDG&E conducted a thorough and rigorous evaluation of the technologies now on the market, plus their capability to interface with the utility’s communications and billing systems. In addition, SDG&E sought competitive bids from potential vendors, while evaluating project management experts to assist in the deployment. SDG&E assessed the potential for sweeping changes in the technology and has developed a plan to incorporate metering and communication advances in the future.

As part of its assessment, SDG&E will begin a series of field tests soon to determine the performance of several meter and communication technologies before making its final selections in mid-2007.

SDG&E’s proposal will require approval from the CPUC before deployment could begin. If approved, the smart meters are expected to reduce system costs through meter-reader cost savings, earlier detection of outages, equipment monitoring and deferred construction costs related to reductions in peak usage.

Utilities Increase Substation Automation Spending

Newton-Evans Research estimates the current annual global spending for substation automation and integration programs at about $550 million to $600 million, with an overall potential market size of nearly $40 billion.

According to the research, the years 2002-2004 were slow-growth-or no-growth-years in most categories of intelligent electronic equipment sales related to the modern, increasingly digital, electric power substation. Few retrofit programs were undertaken except for the most critical of substations.

Newton-Evans further estimates that only about 12 percent of utility-operated substations have been fully automated and integrated by year end 2005. Most of these are in fact newly or recently constructed substations.

Most substation equipment manufacturers (mid size and smaller companies) and integrators that the research company surveyed in the second half of 2005 indicated moderate-to-good growth market conditions within their utility sales sectors, resulting in sales that are as much as 5 percent to 15 percent higher than 2003 or 2004 sales levels.

Economic growth has continued in many electricity dependent sectors. In turn, this spurs demand for increased electric power, and increasingly reliable power. This results in internal planning for infrastructure and automation programs.

There remains some concern in the industry about the dearth of skilled engineering resources due to retirements and layoffs. This may further impact the ability of technology supplier companies to engage utilities for other than short-term requirements. However, third-party engineering and integration service firms are now making significant strides in winning substation automation-related business from planning to design to construction.

If distributed generation activities continue to increase across the world, there is some positive benefit that will occur for the substation automation, integration and retrofit business, as utilities become more involved with DG efforts.

In summary, retrofit substations will be upgraded as warranted, based on load growth, criticality to customers, and development of DG programs. New substations will increasingly be designed and constructed as integrated and automated remote assets for the utility.

Protocol use and plans among North American electric power utilities continue to differ from the trends among utilities in the international communities. North American utilities continue to strongly support DNP 3, and will likely migrate to a LAN version of this protocol.

International utilities tend to use IEC protocols. Currently, the 60870-5-103 protocol is popular, especially in Europe, while migration to IEC 61850 is underway in Europe, the Middle East and Africa, and among some of the largest utilities elsewhere. Nonetheless, Latin American and Asian Pacific utilities report strong use of Modbus and Asia-Pacific utilities tend to align themselves more with DNP 3 at the present time.

This information was gleaned from the four volumes of reports comprising the 2005-2007 series on substation automation and integration published by Newton-Evans Research during the first quarter of 2006.

Additional information on the four volume study “Worldwide Market for Substation Automation and Integration Programs in Electric Utilities: 2005-2007″ is available from Newton-Evans Research Company at

Smart Energy Alliance Brings Together Industry Leaders

The Smart Energy Alliance is a collaboration of technology leaders-Capgemini, HP, Intel, GE, Cisco, and Oracle-who have combined forces to change the creation and deployment of solutions for power distribution operations. Each of these companies brings world-leading expertise, proven innovations and specific utility experience to meet the challenges of the utility industry.

The Smart Energy Alliance works from a roadmap developed in conjunction with some of the largest and most progressive utilities and institutions in the world. This roadmap focuses on an architecture that is modular, flexible and comprehensive-reducing complexity as it integrates various pieces gradually. According to the Alliance, the resulting solutions:

  • Are modular and flexible;
  • Are built with combined expertise;
  • Use equipment, hardware and software components as “services”;
  • Are part of a common communications infrastructure;
  • Reduce isolated “silos” of information;
  • Deliver a real-time view of your business; and,
  • Enable faster time-to-solution.

Because they are based on industry-standard equipment, hardware and software components, these solutions are easy to extend; they also adapt easily to changing business needs. This keeps initial deployment costs low and enables intelligent growth going forward. And, as each Alliance member company is a market leader in their field, each solution comes with extensive utility and cross-industry experience.

Additionally, components are available to multiple operations rather than dedicated to one task, maximizing their utilization and lowering cost, and, as a part of a common communications infrastructure, the solutions reduce the cost of overall deployment, taking advantage of existing systems and allowing for partial roll-outs in critical areas.

Because these solutions consists of services that can “talk” to each other, they replace functional silos-systems that can’t communicate with other systems-with networks of services that share information and data across your company. The result is a fabric that integrates all of the distribution equipment with customer information systems, SCADA, field operations, subcontractors, shop floors, compliance systems and back-end billing systems.

And, because information becomes widely available across your company with these solutions, they can be harnessed to provide true visibility into your operations, enabling faster response to problems, closer collaboration with suppliers and subcontractors, better load balancing and improved demand forecasting. Finally, because the pieces of the solution work together and many parts are pre-integrated by the Alliance companies, integrating them with your existing systems is accelerated.

By combining their utilities expertise within a flexible and modular framework, the Smart Energy Alliance advertises that they build solutions that orchestrate and leverage the innovative technologies that can transform utility operations.

Cal ISO OKs Three Transmission Projects

The California Independent System Operator (California ISO) Board of Governors Operations Committee has approved three major improvements that will strengthen the transmission grid in northern California. The trio of transmission projects will also reduce the cost of managing transmission bottlenecks and maintaining adequate generation for local reliability by approximately $30 million per year. Combined with four smaller projects that did not require board approval, the grid enhancements will add transmission capacity and reduce local generation needs by 700 MW.

The California ISO worked closely with Pacific Gas and Electric (PG&E) to identify these three projects as potentially providing significant economic and reliability benefits:

  • New Vaca Dixon 500/230-kV transformer (online, December 2007),
  • Re-conductor Vaca Dixon-Tulucay-Lakeville 230-kV lines (on line May 2010), and
  • New Oakland C-X #2 115-kV underground cable (online May 2010).

The ISO is taking an integrated approach to transmission planning process, looking at proposed transmission projects on a regional basis to see how each one will interact with other proposals in the area in providing economic and reliability value to the California ratepayers in the ISO footprint.

The overall goal is to approve projects that give consumers the biggest bang for the buck, according to the ISO.