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A AS THE CENTRAL NERVOUS system of the power network, the con trol center—along with its energy management system (EMS)—is a crit ical component of the power system operational reliability picture. Although it is true that utilities have been relying on EMS for over two decades, it is also true that many of the systems in place today are outdated, undermaintained, or underused compared with the total potential value that could be realized.
september/october 2004 IEEE power & energy magazine 49 Factors, trends, and requirements having the biggest impact on developing such systems in the next decade 1540-7977/04/$20.00©2004 IEEE by Faramarz Maghsoodlou, Ralph Masiello, and Terry Ray A AS THE CENTRAL NERVOUS system of the power network, the con- trol center—along with its energy management system (EMS)—is a crit- ical component of the power system operational reliability picture. Although it is true that utilities have been relying on EMS for over two decades, it is also true that many of the systems in place today are outdated, undermaintained, or underused com- pared with the total potential value that could be realized. Many utilities are operating with EMS technology that was installed in the early 1990s; thus, the technology base and functionality is a decade old. The EMS industry overall did not markedly alter its technology in the second half of the decade as the investment priority in the late 1990s turned from generation/reliability- centric to retail/market-centric appli- cations and the need for faster return on investment, which meant mini- mizing customization and imple- menting new advances in technology. EMS technology basically stayed © DIGITAL VISION unchanged, largely unaffected by much of the Internet- driven advances in IT of the past few years. Almost every EMS deployed in the 1990s incorporated state-of-the-art (at the time) network models, for example, state estimation, contingency analyses, and operator study analytical tools. More than half of these systems also includ- ed operator training simulators (OTSs) that were intended to enable operator simulation training analogous to nuclear operator or airline pilot simulator training. In a recent survey conducted by KEMA and META Group, however, it appears that a sizable fraction of utilities that have OTS technology deployed are not actually using it, not because the technology doesn’t work, but because they can not afford the extra staff required to maintain the models, develop the training pro- grams, and conduct and receive training. The market’s shift, beginning in the late 1990s, from an investment strategy focused on improving capacity/reliability to one geared toward meeting the needs of a deregulating market impacted not only day-to-day infrastructure invest- ment but also research and development. At the same time, utilities decreased EMS budgets even further because genera- tion scheduling and optimization came to be viewed as a function of the deregulated side of the new market structure. Transmission entities therefore slashed their EMS budgets and staff, thinking that local independent system operators (ISOs) would assume responsibility for grid security and operational planning. Those factors, combined with the fact that EMS technology has historically lagged behind the IT world in general, has created a situation where control room technology is further behind today than it has ever been. This article examines some of the factors, trends, and requirements that will have the biggest impact on develop- ment of energy management systems in the next decade that are more reliable, secure and flexible, and capable of meeting the anticipated new requirements of pending legislation, deregulation, and open access. Three Lessons Looking past the system failures or applications not function- ing that have been so well publicized in blackout analyses, there are three vitally important lessons that the whole sys- tems operations community should take away from the reports issued by the U.S Canada Power System Outage Task Force. First, the number of alarms—breaker operations and analog measurements of voltage and line flows exceeding limits and oscillating in and out of limits—far exceeded the design points of the systems deployed in the early 1990s. A more realistic design philosophy in light of this would be to develop “worst case” requirements, stipulating that systems must function when all measured points rapidly cycle in and out of alarm. Second, the blackout did not occur instantly. Rather, the voltages collapsed and lines successively tripped over a period of time. Had the operators had good information and tools to guide them relative to what should have been done, it’s feasible that sufficient load could have been shed or other actions taken to have prevented such a widespread outage. In other words, EMS solutions require network modeling and analysis tools that are sufficiently robust to be useful in these conditions. They should converge accurately and reliably under extreme voltage conditions, run fast enough to be useful in the time available, and be able to rec- ommend remedial actions. Third, and perhaps most importantly, the traditional “ N − 1 ”criteria for transmission and operations planning is not adequate. When systems are subject to disturbances, out- ages come in clusters. Once the first outage has happened, subsequent outages are more likely, and multiple outages, due to human error or failure to act, are more likely than we want to acknowledge. Systems and people need procedures and training that takes this into account. Furthermore, the U.S Canada Power System Outage Task Force discovered that, “some companies appear to have had only a limited understanding of the status of the electric sys- tems outside their immediate control.” They also determined that “besides the alarm software failure, Internet links to SCADA software weren’t properly secure and some operators lacked a system to view the status of electric systems outside their immediate control.” Regaining System Control Clark Gellings, EPRI vice president for power delivery and markets, notes that, “the nation’s power delivery sys- tem is being stressed in new ways for which it was not designed” and that “a number of improvements to the sys- tem could minimize the potential threat and severity of any future outages.” 50 IEEE power & energy magazine september/october 2004 There is some ground to be gained by simply getting the EMS technology that is currently in use within the utility industry fully functional again to release the true potential value of the investment. 51 “EPRI believes that the lessons learned from the 14 August power outage will support the development and deployment of a more robust, functional and resilient power delivery system,” he said. In the view of KEMA and META Group, rectifying the shortcomings of our EMS/SCADA systems will be accom- plished in three distinct, sequential phases. See Figure 1. Phase I will encompass an emphasis on control room people, processes, and policies and is happening this year. Phase II will encompass communications and control capabilities, and, in some cases, plans for phase II activities and projects are already underway. Phase III will be investment in infra- structure and intelligence, which will take longer to accom- plish because of difficulties in funding large capital projects and in getting needed regulatory and political approvals. Phase I—People, Processes, and Policies NERC is currently driving phase I, with the formulation of standards for mandatory EMS performance, availability, tracking, reporting, and operator training. Individual utilities and, particularly, the six ISOs in North America are focusing on their own processes and policies (California ISO, ERCOT, ISO New England, Midwest ISO, New York ISO, and PJM). NERC, in conjunction with the U.S Canada Power System Outage Task Force studying the causes and recommendations of the 14 August blackout, attributes inef- fective communications, lack of operator training in recog- nizing and responding to emergencies, inadequate processes for monitoring and compliance assurance, the inadequacy of power system visualization tools, inaccurate data, and inade- quate system protection technologies as key causes of the outage, and the resulting technical and strategic initiatives will cause heavy emphasis to be placed on factors such as ✔ improving operator and reliability coordinator training, leading, KEMA predicts, to resurgence in operator training simulators (OTSs) ✔ evaluating and improving practices and processes focused on reactive power and voltage control, system modeling data, and data exchange ✔ evaluating and revising operating policies and proce- dures to ensure that reliability coordinator and control area functions and responsibilities are clearly defined ✔ evaluating and improving the real-time operating tools and time-synchronized recording devices. Phase II—Communications, Control, and Capabilities Phase II will focus on enhanced communications and control capabilities and on new software applications in control cen- ters. Although more expensive and more difficult than phase I activities, these are an order of magnitude less costly than major infrastructure investments that will occur in phase III. Phase II will include developing a more interconnected approach to communication and control, for example, devel- opment of a regional approach to relay setting and coordina- tion, system planning at a regional level, and implementation of policies, procedures, and technologies that facilitate real- time sharing of data among interconnected regions. The deployment of real-time phasor measurements around the country is being planned and, as this becomes available, the regional control systems at ISOs and regional transmission organizations (RTOs) and NERC regional coor- dinators will develop applications that can use this informa- tion dynamically to help guide operators during disturbances. Phase III—Investment, Infrastructure, and Intelligence The emphasis of phase III will be on investment in enhanced instrumentation and intelligence, along with a renewed investment in the power system infrastructure and the tech- nology to better manage it. The new infrastructure may include, as many propose, FACTS devices and other new transmission technologies and devices providing what we think of as ancillary services (superconducting VAR support, for example). What we do know is that these prospective new technologies will require new modeling and new analysis in EMS applications. EMS and system operations will also have a role to play in transmission planning for straightforward new transmis- sion line infrastructure. We have learned that planning studies not closely aligned with operational data are too abstract. figure 1. Improving the EMS in three phases. Phase I People Processes Policies Phase II Commmunication Control Analytics Phase III Investment Infrastructure Intelligence september/october 2004 IEEE power & energy magazine 52 IEEE power & energy magazine september/october 2004 What matters is how new transmission lines will be operated and how they will impact system operations. EMS systems must have the capacity to provide the data and analysis needed to understand the answers to that question. As investments are made in the EMS solutions of tomor- row, KEMA and META Group believe that several important technology trends will come into play. Visualization Control room visualization today is still limited primarily to one-line diagrams, which are insufficient when it comes to today’s needs to understand the availability of electricity at any given time and location and in understanding load, volt- age levels, real and reactive power flow, phase angles, the impact of transmission-line loading relief (TLR) measures on existing and proposed transactions, and network overloads. In fact, the Department of Energy’s 2002 National Grid Study recommends visualization as means to better understand the power system. Three-dimensional, geo-spatial, and other visualization software will become increasingly indispensable as electricity transactions continue to increase in number and complexity and as power data, historically relevant to a contained group of entities, is increasingly communicated more widely to the ISOs and RTOs charged with managing an open grid. Not only do visualization capabilities enable all parties to display much larger volumes of data as more readily understandable computer-generated images, but they also provide the ability to immediately comprehend rapidly changing situations and react almost instantaneously. Three-dimensional visualization is an invaluable tool for using abstract calculated values to graphically depict reactive power output, impacts of enforcing transmission line constraints, line loadings, and voltages magnitudes, making large volumes of data with complex relationships easily understood. Advanced Metering Technology In this age of real-time information exchange, automated meter reading (AMR) has set new standards by which the energy market can more closely match energy supply and demand through more precise load forecasting and manage- ment, along with programs like demand-side management and time-of-use rate structures. Beyond AMR, however, a host of real-time energy management capabilities are now on the market, which, through wireless communication with commercial, residential, or industrial meters, enable utilities to read meters and collect load data as frequently as once every minute. This enables utilities to better cope with dynamic market changes through real-time access to the criti- cal load forecasting and consumption information needed to optimize decision support. The convergence of demand-response technologies and real-time pricing, wireless communications, and the need figure 2. Real-time event management (courtesy of Gensym Corp.). Inputs Power System Model Respond Diagnose and Explain Outputs Detect Data Events Condition or State Controls Sensors Advice and Corrective Actions How Do I Get the System to the Condition I Want? What Is the Significance of the Data? What Is the State of the System? • Detect • Diagnose and Explain • Respond with Models Knowledge-Based Models Enable Reasoning september/october 2004 IEEE power & energy magazine for more reliable and timely settlement processes are all drivers for enhanced metering capabilities. This, in turn, will create a demand for EMS solutions capable of handling much larger volumes of data and the analytical tools to manage this data. More Stringent Alarm Performance The 2003 blackout drew attention to what has become a potentially overwhelming problem—SCADA/EMS has little or no ability to suppress the bombardment of alarms that can overwhelm control room personnel during a rapidly escalat- ing event. In a matter of minutes, thousands of warnings can flood the screens of dispatchers facing an outage situation, causing them to ignore the very system that’s been put in place to help them. Although distribution SCADA has been able to take advantage of straightforward priority and filtering schemes to reduce the alarm overload, the transmission operations sys- tems have not. This is because transmission systems are net- worked, and it is more difficult to analyze the alarms to determine what needs to be shown to help the operator reach a conclusion. Also, reaction time is not an issue in distribu- tion, and there is more value in taking the time to locate the fault before taking action; short outages can be tolerated. Other industries, for example telecom, networking, and refin- ing, have had good success with inference engines and other rule-based systems for diagnosing alarm conditions and pro- viding operator assistance. These are worth a second look by the EMS fraternity today. New analytical tools are needed in the EMS to enable operators to manage and respond to abnormal events and conditions. See Figure 2. Lessons learned in other industries in the application of model- and rule-based reasoning methodologies in large-scale real-time systems can be applied here. These tools will be expected to provide the fol- lowing capabilities: ✔ proactively monitor system conditions to avoid or minimize disruptions ✔ analyze, filter, and correlate alarms to speed up operator responses ✔ rapidly isolate the root cause of problems to accelerate resolution ✔ guide operators through system recovery and service restoration ✔ provide expert guidance so that operators of all skill levels can effectively respond to problems ✔ predict the impact of system events and disturbances so operators can prioritize actions. Also to be watched is the promise of the digital dash- board, heretofore unfulfilled in the control room environ- ment, but offering the ability to integrate information from many sources into information portals that provide ready desktop access to the data each user needs to perform his or her job functions, with an emphasis on business intelligence and knowledge management. Data Warehousing For many years, utilities have been archiving the operational (real-time) and nonoperational (historic) information cap- tured by energy management systems. Today’s thought lead- ership shift is to focus on how this archived operational and nonoperational data can be combined with emerging analytic functionality to meet a host of business needs, for example, to more readily identify parts of the network that are at the greatest risk of potential failure. If integrated properly, heads- up information stored by these systems can also aid utilities in proactive replacement or reinforcement of weak links, thus reducing the probability of unplanned events. A recent study conducted by IBM showed that today, the typical company utilizes only 2–4% of the data collected in operational systems. Data marts are one way to more fully leverage and use data to produce measurable improvements in business performance. A data mart, as defined in this article, is a repository of the measurement and event data recorded by automated systems. This data might be stored in an enterprise-wide database, data warehouse, or specialized database. In practice, the terms data mart and data warehouse are sometimes used interchangeably; however, a data mart tends to start from the analysis of user needs, while a data warehouse starts from an analysis of what data already exists and how it can be collected in such a way that it can be used later. The emphasis of a data mart is on meeting the specific demands of a particular group of users in terms of analysis, content, presentation, and ease of use. Most automated utility systems are installed by the vendor with built-in data marts developed specifically to archive data for that problem domain. For some utilities, this means a decade of logged historical performance data is available for integration and analysis. The real need is to model and simulate the grid on an ongoing basis to understand how it responds. Knowledge gained from simulations through tools such as state 53 EMSs should converge accurately and reliably under extreme voltage conditions, run fast enough to be useful in the time available, and be able to recommend remedial actions. estimation and contingency analysis allows protection to be built into the system at the local or control levels. Operators can also use this knowledge to recognize pat- terns leading up to potential failure and take corrective action long before the situation becomes a crisis. State estimation combined with contingency analysis to support automated decision rules or human intervention is the most practical approach to addressing future grid vulnerability. It is possible to fine tune reliability centered maintenance (RCM) and better schedule transformer maintenance/replace- ment if the hourly loading history of a transformer can be correlated with ambient temperature conditions. The data needed to do this is readily available from SCADA systems. This is an example of time-series data being stored in a data warehouse designed for the task, such as PI Historian. Another example is that, to demonstrate compliance with code of conduct and reliability procedures, it is necessary to track all the approvals and operational actions associated with a transformer outage. This is a combination of transactional information (requests and approvals) and event information (control actions and alarms), linked over time. This requires the combination of a transactional data mart triggered by entries on screens and data collection in real time. A third example is that reliability centered maintenance is enhanced if the distortions in the 60-Hz waveforms on electrical measurements at the transformer can be tracked over time. This is a waveform analysis over a sampled time series. It requires interaction with a substation computer and is not easily support- ed in either a transactional or time-series database. The solution lies in the kinds of proprietary systems used for similar RCM work against jet engines and combustion turbines. Risk Management and Security Many utilities are coming to the realization that compli- ance with the Sarbanes Oxley (SOX) can be extended to mean that EMS systems and their shortcomings present serious risk issues that must be addressed to prevent the financial penalties that could accrue as a result of a long-term outage. Similarly, when a utility has a rate case pending or operates under performance-based rates measured by reliability, there is a direct connection between the EMS and the financial ramifications of less-than- desirable results. Therefore, the impact of Sarbanes Oxley on operations will impact EMS systems—in terms of relia- bility, operator training, the availability of software/systems that provide improved record keeping of who author- ized what, and adherence to standards. Look for the application of technolo- gies that reduce risk by providing key per- formance indicators that help managers determine whether critical operating parameters are within expectations and that combine accurate cost/revenue meter- ing, power quality, and reliability monitoring to deliver rele- vant information in a timely fashion. There are three broad families of SOX relevance to EMS. See Figure 3. First is the financial impact of loss of an EMS system and the measures taken to mitigate such loss. One num- ber is used for loss of EMS for up to an hour measured in the efficiency loss of running units off dispatch, failing to meet schedules and paying balancing costs, etc. Another higher fig- ure is used if EMS is out for a day to a week, resulting in manu- al workarounds, extra staff in the field, and inefficiencies and costs incurred due to overconservative operations. A third, even higher number, is used for longer outages as those temporary costs become permanent and emergency extra staff or extra sys- tems are deployed. The second and third numbers are worsened by increased probability of major outages with all its costs. Second, SOX requires certification of cybersecurity and of the quality controls imposed on the software in production. This will have implications on the QA and software life-cycle management tools and methods used by vendors and consult- ants as well as utilities. Finally, there is a need to show compliance with NERC, ISO, code of conduct, and other standards for operations. EMS must be enhanced to provide easily recovered audit trails of all sorts of actions and system performance to pro- vide compliance reports and analyses. Advanced Network Analysis Applications Another key factor that is critical to the success of the EMS technology of tomorrow is the incorporation of advanced net- work analysis algorithms and applications. Most systems in place today are still based on the Newton-Raphson power flow analysis and related/derivative methodologies, with their inherent shortcoming being that they fail to converge when network conditions are too far from nominal, especially in times of near voltage collapse. For real-time calculations, dif- 54 IEEE power & energy magazine september/october 2004 figure 3. Sarbanes Oxley relevance to EMS. Sarbanes-Oxley Act Compliance Financial Impact of Loss of the EMS System Certification of Cybersecurity and Quality of Software Compliance with NERC, ISO, and Other Standards Code of Conduct september/october 2004 IEEE power & energy magazine ferent idealizations of the model are needed to speed up the ability to solve large series of power flows within a reason- able time frame. Projects recently completed in Spain may have resulted in new algorithms that are noniterative and that are much more robust than Newton-Raphson, which could help with handling low-voltage conditions. Another needed improvement in application analysis falls within the realm of state estimation. In most state estimation applications, measurements are obtained by the data acquisi- tion system throughout the whole supervised network, at approximately the same time, and are centrally processed by a static-state estimator at regular intervals or on operator request. Although today’s high speed data acquisition tech- nology is capable of obtaining new sets of measurements every 1–10 seconds, current EMS technology allows state estimation processing only every few minutes within the cost parameters allowed for EMS. A more reliable state estimation operational scheme can be achieved by shortening the time interval between consecutive state estimations to allow a closer monitoring of the system, particularly in emergency situations in which the system state changes rapidly. This mandates development of faster state estimation algorithms and on the numerical stability of these algorithms. Other domains have advanced state estimation technology considerably since it was introduced to electric power. Techniques such as sequential state estimation are worth looking at, especially for ISO/RTO applications where the time synchronization of the analog measurements is not as robustly enforced. Operator/Dispatcher Training Simulator Most EMS systems deployed in the 1990s already include OTS functionality, but a recent survey initiated by KEMA and META Group indicates that many are not in use, primari- ly due to the lack of staff to support them and conduct the training. Based on the recommendations of NERC and other industry and regulatory groups, this will change as more utili- ties take the steps needed to leverage the technological capa- bilities they already possess. As with other network analysis applications, OTS needs to have robust algorithms that are capable of simulating abnor- mal voltage conditions. It is also imperative that the represen- tation of network and equipment models in OTS be consistent with those used in real-time applications to realisti- cally simulate current and potential future conditions. Ideally, all model updates in the real-time system should be automati- cally propagated to OTS to keep the two models in synch. The OTS will also be called upon to support “group” training of transmission operations and ISO operation; therefore, the network and process modeling has to be coordinated hierar- chically across the individual utilities and the ISO. Communication Protocols EMS systems must have the capacity to talk to “legacy,” i.e., preexisting, remote terminal units (RTUs) and, thus, are severely handicapped today in that many still rely on serial RTU protocols that evolved in an era of very limited band- width. As a result, most EMS solutions in use today are unable to exploit breakthroughs in communications, in partic- ular, secure communications such as encryption and valida- tion. This will need to change. Eventually, the need for encrypted, secure communications to the RTU, combined with adoption of substation automation and substation com- puters, may lead to the end of RTU protocols as we know them today and adoption of a common information model (CIM)-based data model for the acquisition of field data. Enterprise Architectures To achieve the benefits offered by the technologies described here, EMS solutions need to be able to take advantage of modern enterprise architectures (EAs). EMS systems are typically not included as part of utility EA initiatives, but as their importance becomes readily apparent, this will change. Though EA defini- tions vary, they share the notion of a comprehensive blueprint for an organization’s business processes and IT investments. The scope is the entire enterprise, including the control room, and, increasingly, the utility’s partners, vendors, and customers. A strategic information asset base, the EA effectively defines the business, the information necessary to operate the business, the technologies necessary to support the business operations, and the transitional processes necessary for implementing new technologies in response to changing busi- ness or regulatory requirements. Further, it allows a utility to analyze its internal processes in new ways that are defined by changing business opportunities or regulatory requirements instead of by preconceived systems design (such as monolith- ic data processing applications). In this architectural design, an object model represents all aspects of the business, includ- ing what is known, what the business does, the business con- straints, and the business’ interactions and relationships. More practically, a good EA can provide the first com- plete view of a utility’s IT resources and how they relate to business processes. Getting from a utility’s existing or base- line architecture to an effective EA requires defining both a target architecture and its relationship to business processes, as well as the road map for achieving this target. An effective EA will encompass a set of specifically defined artifacts or systems models and include linkages between business objec- tives, information content, and information technology capa- bilities. Typically, this will include definitions of ✔ business processes, containing the tasks performed by each entity, plus anticipated change agents such as pending legislation or regulations that might impact business processes ✔ information and the way it flows among business processes ✔ applications for processing the information ✔ a model of the data processed by the utility’s informa- tion systems ✔ a description of the technology infrastructure’s func- tional characteristics, capabilities, and connections. 55 Though no industry-standard technical/technology reference model exists for defining an EA, it is clear that component- based software standards, such as Web services, as well as pop- ular data-exchange standards, such as the extensible markup language (XML), are preferred, as are systems that are interop- erable, scalable, and secure, such as Sun Microsystem’s Java 2, Enterprise Edition (J2EE) plat- form, or Microsoft’s .Net framework. It is also clear that frameworks and initiatives, such as the Zachman frame- work, Federal Enterprise Architecture Framework (FEAF), The Open Group Architecture Framework (TOGAF), and Rational Uni- fied Process (RUP), will strongly impact how enterprise architectures for utility control operations are defined and implemented. See Figure 4. By using shared, reusable business models (not just objects) on an enterprise- wide scale, the EA provides tremendous benefits through the combination of improved organizational, operational, and technological effectiveness for the entire enterprise. Web Services Architecture There are no EMS deployments today that take advantage of modern Web services architecture, although the architecture is providing tremendous benefits to businesses around the world and holds big promise for control room operations. Past attempts at distributed computing have resulted in systems where the coupling between the system’s various components are both too tight and too easily broken for many of the transactions that utilities should be able to perform via the Internet. The bulk of today’s IT systems, including Web- oriented systems, can be characterized as tightly coupled applications and subsystems. Monolithic systems like these are sensitive to change, and a change in the output of one of the subsystems often causes the whole system to break. A switch to a new implementa- tion of a subsystem will also often cause a breakdown in col- laboration among systems. As scale, demand, volume, and rate of business change increase, this weakness can become a serious problem marked by unavailable or unresponsive Web sites, lack of speed to market with new products and services, or inability to meet new business opportunities or competitive threats. As a result, the current trend is to move away from tightly coupled monolithic systems and towards loosely coupled systems of dynamically bound components. Web services provide a standard means of interoperability between dif- ferent software applications running on a variety of plat- forms or frameworks. They are comprised of self-contained, modular appli- cations that can be described, published, located, and invoked over the Internet, and the Web services architecture is a logical evolution of object-oriented design, with a focus on components geared toward e-business solutions. Like object-oriented design, Web services encompass fun- damental concepts like encapsulation, message passing, dynamic binding, and service description and querying. With a Web services architecture, everything is a “service,” encap- sulating behavior and providing the behavior through an API that can be invoked for use by other services on the network. Systems built with these principles are more likely to domi- nate the next generation of e-business systems, with flexibili- ty being the overriding characteristic of their success. As utilities move more of their existing IT applications to the Internet, a Web services architecture will enable them to take strong advantage of e-portals and to leverage standards, such as XML; Universal Description, Discovery, and Integra- tion (UDDI); Simple Object Access Protocol (SOAP); Web Services Definition Language (WSDL); Web Services Flow Language (WSFL); J2EE; and Microsoft.NET. The Web services architecture provides several benefits, including: ✔ promoting interoperability by minimizing the require- ments for shared understanding 56 IEEE power & energy magazine september/october 2004 Another key factor that is critical to the success of the EMS technology of tomorrow is the incorporation of advanced network analysis algorithms and applications. figure 4. Integration standards. BizTalk, XML.org OAGIS, UIG-XML, CCAPI, CIM XML J2EE (EJB) CORBA MSFT .Net (COM+) IP UMLWorkflow Semantics Format Interaction Security Integrity Transport september/october 2004 IEEE power & energy magazine ✔ enabling just-in-time integration ✔ reducing complexity by encapsulation ✔ enabling interoperability of legacy applications. Cybersecurity Standards Used throughout the industrial infrastructure, control systems have been designed to be efficient rather than secure. As a result, distributed control systems (DCSs), programmable logic controllers (PLCs), and supervisory control and data acquisition (SCADA) systems present attractive targets for both intentional and unintentional catastrophic events. To better secure the control systems controlling the critical infrastructures, there is a need for the government to support the energy utility industry in two critical areas: ✔ establish an industry-wide information collection and analysis center for control systems modeled after Com- puter Emergency Response Team (CERT) to provide information and awareness of control systems vulnera- bilities to users and industry ✔ provide sufficient funding for the National SCADA Test Bed to facilitate the timely and adequate determi- nation of the actual vulnerabilities of the various con- trol systems available in the market and develop appropriate mitigation measures. Between the need for improved cybersecurity and Sar- banes Oxley, the EMS world is likely to see a strong move toward software that is “certifiable” to ensure that the code is “clean.” This implies the need for modern, automated, com- prehensive quality assurance processes and an ability to veri- fy system performance on a regular basis. Summary It’s clear that today’s EMS/SCADA systems have a long way to go to meet the reliability and regulatory standards of today’s evolving markets. This presents not only a challenge, but also an opportunity to invest in new technology that will enable us to more effectively manage both the supply and demand side of the energy equation and is an equally impor- tant component to any long-term energy policy. Apart from demonstrating the vulnerability of the electric grid, the 2003 blackout put enormous pressure on the energy industry to show that it is serious about improving reliability. Although long-term infrastructure needs will require an enor- mous capital investment, estimated by some at US$10 billion a year for the next decade, at the very least, there are numerous steps that can be taken toward greatly enhanced reliability through much smaller investments in processes and technology. Four key pieces of advice are as follows: One, there is some ground to be gained by simply getting the EMS tech- nology that is currently in use within the utility industry fully functional again to release the true potential value of the investment. Two, reinvigorate OTS and training programs. Three, investigate more robust approaches to network analy- ses, and, four, take the steps necessary to minimize the poten- tial financial impact of Sarbanes Oxley. For Further Reading U.S Canada Power System Outage Task Force. Final Report on the August 14th Blackout in the United States and Canada [Online]. Available: https://reports.energy.gov/ “Emerging tools target blackout prevention,” Comput. World, Aug. 25, 2003. [Online]. Available: http://computerworld.com.secu- ritytopics/security/recoverystory/0,10801,84322,00.html Tuscon Electric Power press release [Online]. Available: http://www.elequant.com.news/pr_20040526.html Elequant launch press release [Online]. Available: http://www.elequant.com.news/pr_20040605a.html Biographies Faramarz Maghsoodlou is an executive consultant and director of systems and technology services with KEMA, Inc. With over 25 years of experience in the energy and software industry, he specializes in energy systems plan- ning, operation, and optimization and enterprise software applications. He can be reached at fmaghsoodlou@kema- consulting.com Ralph Masiello is senior vice president, bulk power con- sulting, with KEMA Inc. A Fellow of the IEEE, he has over 20 years experience in transmission and distribution opera- tions and in control systems implementations at many of North America’s largest utilities. He can be reached at rmasiello@kemaconsulting.com Terr y Ray is vice president, energy information strategies, with META Group Inc. With over 35 years experience in the energy industry, he specializes in advising clients on the align- ment of business and IT strategies. He has worked with investor- owned and public power organizations in North America and Europe. He can be reached at terry.ray@metagroup.com 57 The 2003 blackout drew attention to a potentially overwhelming problem—SCADA/EMS has little or no ability to suppress the bombardment of alarms that can overwhelm control room personnel during a rapidly escalating event. p&e . september/october 2004 IEEE power & energy magazine 49 Factors, trends, and requirements having the biggest impact on developing such systems in the next decade 1540-7977/04/$20.00©2004 IEEE by Faramarz. II Commmunication Control Analytics Phase III Investment Infrastructure Intelligence september/october 2004 IEEE power & energy magazine 52 IEEE power & energy magazine september/october 2004 What matters is how new. manage- ment, along with programs like demand-side management and time-of-use rate structures. Beyond AMR, however, a host of real-time energy management capabilities are now on the market, which,