Reliability Technology Issues and Needs Assessment

Large blackouts, such as the August 14-15, 2003 blackout in the northeastern United States and Canada, focus attention on the importance of reliable electric service. As public and private efforts are undertaken to improve reliability and prevent power interruptions, it is appropriate to assess their effectiveness. Measures of reliability, such as the frequency and duration of power interruptions, have been reported by electric utilities to state public utility commissions for many years. This study examines current state and utility practices for collecting and reporting electricity reliability information and discusses challenges that arise in assessing reliability because of differences among these practices. The study is based primarily on reliability information for 2006 reported by 123 utilities to 37 state public utility commissions.

The massive electric power blackout in the northeastern United States and Canada on August 14-15, 2003 resulted in the U.S. electricity system being called "antiquated" and catalyzed discussions about modernizing the grid. Industry sources suggested that investments of $50 to $100 billion would be needed. This report seeks to quantify an important piece of information that has been missing from these discussions: how much do power interruptions and fluctuations in power quality (power-quality events) cost U.S. electricity consumers? Accurately estimating this cost will help assess the potential benefits of investments in improving the reliability of the grid.

Power-quality events are of increasing concern for the economy because today's equipment, particularly computers and automated manufacturing devices, is susceptible to these imperceptible voltage changes. A small variation in voltage can cause this equipment to shut down for long periods, resulting in significant business losses. Tiny variations in power quality are difficult to detect except with expensive monitoring equipment used by trained technicians, so many electricity customers are unaware of the role of power-quality events in equipment malfunctioning.

This report describes the findings from a pilot study coordinated through the Silicon Valley Manufacturers Group in California to explore the capabilities of I-Grid^®, a new power-quality monitoring system. This system is designed to improve the accessibility of power-quality information and to increase understanding of the growing importance of electricity reliability and power quality to the economy.

The study used data collected by I-Grid sensors at seven Silicon Valley firms to investigate the impacts of power quality on individual study participants as well as to explore the capabilities of the I-Grid system to detect events on the larger electricity grid by means of correlation of data from the sensors at the different sites. In addition, study participants were interviewed about the value they place on power quality, and their efforts to address electricity-reliability and power quality problems. Issues were identified that should be taken into consideration in developing a larger, potentially nationwide, network of power-quality sensors.

A clear understanding of the monetary value that customers place on reliability and the factors that give rise to higher and lower values is an essential tool in determining investment in the grid. The recent National Transmission Grid Study recognizes the need for this information as one of growing importance for both public and private decision makers. In response, the U.S. Department of Energy has undertaken this study, as a first step toward addressing the current absence of consistent data needed to support better estimates of the economic value of electricity reliability. Twenty-four studies, conducted by eight electric utilities between 1989 and 2002 representing residential and commercial/industrial (small, medium and large) customer groups, were chosen for analysis. The studies cover virtually all of the Southeast, most of the western United States, including California, rural Washington and Oregon, and the Midwest south and east of Chicago. All variables were standardized to a consistent metric and dollar amounts were adjusted to the 2002 CPI. The data were then incorporated into a meta-database in which each outage scenario (e.g., the loss of electric service for one hour on a weekday summer afternoon) is treated as an independent case or record both to permit comparisons between outage characteristics and to increase the statistical power of analysis results.

Unadjusted average outage costs and Tobit models that estimate customer damage functions are presented. The customer damage functions express customer outage costs for a given outage scenario and customer class as a function of location, time of day, consumption, and business type. One can use the damage functions to calculate outage costs for specific customer types. For example, using the customer damage functions, the cost experienced by an "average" customer resulting from a 1 hour summer afternoon outage is estimated to be approximately $3 for a residential customer, $1,200 for small-medium commercial and industrial customer, and $82,000 for large commercial and industrial customer. Future work to improve the quality and coverage of information on the value of electricity reliability to customers is described.

This report describes a new approach for collecting information on power quality and reliability and making it available in the public domain. Making this information readily available in a form that is meaningful to electricity consumers is necessary for enabling more informed private and public decisions regarding electricity reliability. The system dramatically reduces the cost (and expertise) needed for customers to obtain information on the most significant power quality events, called voltage sags and interruptions. The system also offers widespread access to information on power quality collected from multiple sites and the potential for capturing information on the impacts of power quality problems, together enabling a wide variety of analysis and benchmarking to improve system reliability. Six case studies demonstrate selected functionality and capabilities of the system, including:

• Linking measured power quality events to process interruption and downtime;
• Demonstrating the ability to correlate events recorded by multiple monitors to narrow and confirm the causes of power quality events; and
• Benchmarking power quality and reliability on a firm and regional basis.

During the past three years, working with more than 150 organizations representing public and private stakeholders, EPRI has developed the Electricity Technology Roadmap. The Roadmap identifies several major strategic challenges that must be successfully addressed to ensure a sustainable future in which electricity continues to play an important role in economic growth. Articulation of these anticipated trends and challenges requires a detailed understanding of the role and importance of reliable electricity in different sectors of the economy. This report is intended to contribute to that understanding by analyzing key aspects of trends in the economic value of electricity reliability in the U.S. economy.

We first present a review of recent literature on electricity reliability costs. Next, we describe three distinct end-use approaches for tracking trends in reliability needs: 1) an analysis of the electricity-use requirements of office equipment in different commercial sectors; 2) an examination of the use of aggregate statistical indicators of industrial electricity use and economic activity to identify high reliability-requirement customer market segments; and 3) a case study of cleanrooms, which is a cross-cutting market segment known to have high reliability requirements. Finally, we present insurance industry perspectives on electricity reliability as an example of a financial tool for addressing customers reliability needs.

California is on a path to increase usage of renewable resources. The renewable capacity additions that will be needed are 20,000 megawatts (MW) to achieve 33 percent renewables by 2030 and 40,000 MW to achieve 50 percent renewables by 2030. For this scoping study, a mid-range estimate of 30,000 MW is assumed to be needed over the next 20 years.

Renewable resources are typically located in remote locations, not near the load centers. Nearly two-thirds or 20,000 MW of new renewable resources needed are likely to be delivered to Los Angeles Basin transmission gateways. Integration of renewable resources requires interconnection to the power grid, expansion of the transmission system capability between the backbone power grid and transmission gateways, and increase in delivery capacity from transmission gateways to the local load centers.

To scope the transmission, operations, and reliability issues for renewables integration, this research focused on the Los Angeles Basin Area transmission gateways where most of new renewables are likely. Necessary actions for successful renewables integration include:

• Expand Los Angeles Basin Area transmission gateway and nomogram (a graph depicting three curves representing different variables so that a line intersecting all three curves intersects the related values of each variable) limits by 10,000 to 20,000 MW.
• Upgrade local transmission network for deliverability to load centers.
• Secure additional storage, demand management, automatic load control, dynamic pricing, and other resources that meet regulation and ramping needed in real-time operations.
• Enhance local voltage support.
• Expand deliverability from Los Angeles to San Diego and Northern California.

During the past three years, government and private organizations have issued more than a dozen studies of the benefits and costs of Regional Transmission Organizations (RTOs). Most of these studies have focused on benefits that can be readily estimated using traditional production-cost simulation techniques, which compare the cost of centralized dispatch under an RTO to dispatch in the absence of an RTO, and on costs associated with RTO start-up and operation. Taken as a whole, it is difficult to draw definitive conclusions from these studies because they have not examined potentially much larger benefits (and costs) resulting from the impacts of RTOs on reliability management, generation and transmission investment and operation, and wholesale electricity market operation.

This report: 1) Describes the history of benefit-cost analysis of FERC electricity restructuring policies; 2) Reviews current practice by analyzing 11 RTO benefit-cost studies that were published between 2002 and 2004 and makes recommendations to improve the documentation of data and methods and the presentation of findings in future studies that focus primarily on estimating short-run economic impacts; and 3) Reviews important impacts of FERC policies that have been overlooked or incompletely treated by recent RTO benefit-cost studies and the challenges to crafting more comprehensive assessments of these impacts based on actual performance, including impacts on reliability management, generation and transmission investment and operation, and wholesale electricity market operation.

This report is a scoping study to examine research opportunities to improve the accuracy of the system dynamic load and generator models, data and performance assessment tools used by CAISO operations engineers and planning engineers, as well as those used by their counterparts at the California utilities, to establish safe operating margins. Model-based simulations are commonly used to assess the impact of credible contingencies in order to determine system operating limits (path ratings, etc.) to ensure compliance with NERC and WECC reliability requirements. Improved models and a better understanding of the impact of uncertainties in these models will increase the reliability of grid operations by allowing operators to more accurately study system voltage problems and the dynamic stability response of the system to disturbances.

In March 2005, the Midwest Independent System Operator (MISO) will begin operating the first ever, formal wholesale market for electricity in the central and upper Midwestern portion of the United States. Region-wide, centralized, security-constrained, bid-based dispatch will replace the current system of decentralized dispatch by individual utilities and control areas.

This report focuses on how the operation of generators may change under centralized dispatch. We analyze a stylized example of these changes by comparing a base case dispatch based on a "snapshot" taken from MISO's state estimator for an actual, historical dispatch (4 p.m., July 7, 2003) to a hypothetical, centralized dispatch that seeks to minimize the total system cost of production, using estimated cost data collected by the EIA. Based on these changes in dispatch, we calculate locational marginal prices, which in turn reveals the location of congestion within MISO's footprint, as well as the distribution of congestion revenues. We also consider two sensitivity scenarios that examine 1) the effect of changes in MISO membership (2003 vs. 2004 membership lists), and 2) different load and electrical data, based on a snapshot from a different date and time (1 p.m., Feb. 18, 2004).

Although our analysis offers important insights into how the MISO market could operate when it opens, we do not address the question of the total benefits or costs of creating a wholesale market in the Midwest.

The objective of this Public Interest Energy Research (PIER) scoping project is to identify options for public-interest research and development (R&D) to improve transmission-planning tools, techniques, and methods. The information presented was gathered through a review of current California utility, California Independent System Operator (ISO), and related western states electricity transmission-planning activities and emerging needs. This report presents the project team's findings organized under six topic areas and identifies 17 distinct R&D activities to improve transmission-planning in California and the West. The findings in this report are intended for use, along with other materials, by PIER staff, to facilitate discussions with stakeholders that will ultimately lead to development of a portfolio of transmission-planning R&D activities for the PIER program.

California's high voltage interconnections to neighboring states have played a vital role in meeting the state's electricity needs reliably and at great savings to the customers. However, due to changing industry structure and financial uncertainties, construction of transmission capacity has not kept up with the increase in load or with the addition of generation capacity. There is a need for the development of an evaluation methodology that will include strategic benefits from transmission lines.

This report addresses the need to capture the long-term benefits of transmission lines, including a perspective that transmission lines are a "public good" and therefore, should be evaluated using a social discount rate. This report provides recommendations to adapt and modify the CA ISO proposed evaluation methodology to capture the long-term benefits that transmission projects may provide.

This report is designed to help policymakers focus on the long term and take steps now to plan for a robust and secure electricity infrastructure. Ultimately, a balanced and diversified resource strategy would utilize conservation, load management, renewables, distributed generation, and new interconnections and power plants. California also needs to plan for its future electricity needs by addressing other issues, e.g., fuel mix, energy efficiency, siting, transmission, and gas transportation. This report does not advocate any particular fuel source. It attempts to paint the situation in 2030 and concludes that new interconnections to resource-rich regions and new market hubs will be a part of California's future, and therefore California needs to take steps now to meet its future electricity needs.

California's investments in its transmission grid and interconnections to neighboring states have produced substantial reliability, economic, environmental, and fuel diversity benefits. Since the late 1960s, the investments in interconnections have totaled approximately $4.1 billion. These investments have produced substantial benefits.

The California Independent System Operator's (CAISO) authorized Transmission Access Charge (TAC) for 2003 is approximately $390 million and equates to a cost of approximately 0.2¢/kWh or $2/MWh. If the State of California took a proactive role and invested $3 billion in strategic transmission interconnections over the next two decades, the rate impact would be equivalent to the current CAISO transmission access charge and represent approximately a 0.2¢/kWh or $2/MWh increase, or less than 2% increase in residential rates. The issue for policy makers is whether or not the benefits associated with strategic transmission assets justify the minor rate impact over time. The benefits associated with California's strategic transmission assets.

California needs to resume its leadership in the Western Interconnection to develop strategic interconnections, invest in technologies to improve utilization of existing transmission infrastructure, and develop new approaches to planning and valuing transmission investments. This report provides a summary of the specific recommendations for California transmission.

This report reviews reports of congestion costs and begins to assess their implications for the current national discussion on the importance of the U.S. electricity transmission system for enabling competitive wholesale electricity markets. We draw the following conclusions: 1) Information about the operation of congestion revenue rights markets is needed to assess the impacts of congestion revenue charges on consumers; 2) Information on generators' offers is needed to assess system redispatch payments; 3) Many studies presume that generator offers reflect competitive market conditions; 4) Customer costs may rise as a result of reducing congestion; 5) Minimizing consumer costs may not increase aggregate social wealth; and 6) There is no standardized conceptual framework for studies of congestion costs.

This report catalogs the results of a brief survey, conducted in early 2003, designed to answer the question "What DOE Laboratories electric power grid modeling and analysis software tools are available today that might be of value in carrying out a next-generation National Transmission Grid Study?" Software tool capabilities are described as answers by respondents to a standardized questionnaire, and are summarized by a datasheet for each tool. This survey does not address the significantly broader universe of tools and capabilities actively under research and development within the Laboratories, but not ready for use.

KEMA Consulting has assessed existing commercial tools in the U.S. market that might be used to help support future DOE assessments of national interest transmission bottlenecks, consistent with recommendations in the DOE National Transmission Grid Study. The tool or tools must be capable of supporting studies of power systems transmission, energy, and ancillary services and markets as well as trading behavior.

This report describes the study findings, which are based on interviews and discussions with the nation's six established ISO/RTOs - the California ISO, the New York ISO, the Midwest ISO, ISO New England, the Electric Reliability Council of Texas, and the PJM Interconnection. In addition, this report summarizes information on bottlenecks gathered from other sources, including the Federal Energy Regulatory Commission, the Western Governors' Association, the North American Electric Reliability Council, and the Edison Electric Institute.

The California Energy Commission directed the Consortium for Electric Reliability Technology Solutions to analyze possible future scenarios for the California electricity system and assess transmission research and development (R&D) needs, with special emphasis on prioritizing public-interest R&D needs, using criteria developed by the Energy Commission. The scenarios analyzed in this report are not predictions, nor do they express policy preferences of the project participants or the Energy Commission. The public-interest R&D needs that are identified as a result of the analysis are one input that will be considered by the Energy Commission's Public Interest Energy Research staff in preparing a transmission R&D plan.

In 1999, the Department of Energy (DOE) Transmission Reliability Program commissioned the preparation of six White Papers to establish the foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring.

• "The Federal Role in Electric System Reliability RD&D During a Time of Industry Transition: An Application of Scenario Analysis," by J. Eto
  
• "Review of Recent Reliability Issues and System Events," by J. Hauer and J. Dagle
  
• "Review of the Structure of Bulk Power Markets," by B. Kirby and J. Kueck
  
• "Accommodating Uncertainty in Planning and Operations," by M. Ivey, A. Akhil, D. Robinson, K. Stamber, J. Stamp, and K. Chu
  
• "Real Time Security Monitoring and Control of Power Systems," by G. Gross, A. Bose, C. Demarco, M. Pai, J. Thorp, and P. Varaiya
  
• "Interconnection and Controls for Reliable, Large Scale Integration of Distributed Energy Resources" by V. Budhraja, C. Martinez, J. Dyer, and M. Kondragunta
  

This document is a compilation and synthesis of the executive summaries from each of the white papers. It has been prepared as summary of the key findings from the project and is intended to complement the individual white papers.

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we develop scenarios that represent four possible states of the industry during the next three to 10 years. We outline the RD&D they require and describe appropriate federal roles in making these investments.

We conclude that the federal government has special responsibilities for ensuring adequate investments in electric system reliability RD&D during industry restructuring. Once a stable industry structure with vibrant private-sector RD&D is established, the federal government should assume its historic role of supporting very long-range RD&D activities to complement the private-sector's RD&D investments. During a time of industry transition, however, the private sector faces significant uncertainties that dramatically reduce and narrow the scope of its willingness to invest in RD&D. Thus, without federal support, significant RD&D gaps are likely to emerge. Equally importantly, unbiased federal RD&D is needed to help inform decision makers whose actions will have lasting consequences for the future reliability of the electricity industry. Federal RD&D should be market enabling, not market determining. In view of the importance of electricity grid reliability to national welfare, these factors now call for an increased federal role in electric system reliability RD&D.

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we review, analyze, and evaluate critical reliability issues as demonstrated by recent disturbance events in the North America power system. Eleven major disturbances are examined. Most of them occurred in this decade. Two earlier ones—in 1965 and 1977—are included as early indictors of technical problems that persist to the present day. The system events are assessed for both their technological and their institutional implications. Policy issues are noted in passing, in so much as policy and policy changes define the most important forces that shape power system reliability on this continent.

The strategic challenge is that the pattern of technical need has persisted for so long. Anticipation of market deregulation has, for more than a decade, been a major disincentive to new investments in system capacity. It has also inspired reduced maintenance of existing assets. A massive infusion of better technology is emerging as the final option for continued reliability of electrical services. If that technology investment will not be made in a timely manner, then that fact should be recognized and North America should plan its adjustments to a very different level of electrical service.

It is also apparent that technical operations staff among the utilities can be very effective at marshaling their forces in the immediate aftermath of a system emergency, and that serious disturbances often lead to improved mechanisms for coordinated operation. It is not at all apparent that such efforts can be sustained through voluntary reliability organizations in which utility personnel external to those organizations do most of the technical work.

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we review six restructured market systems: California; Pennsylvania, New Jersey, Maryland (PJM); New England; United Kingdom; Alberta; and Australia.

Restructuring is not changing the physical needs of the power system. However, the functions previously performed by the vertically integrated utility must be accommodated by the new market structure. A basic feature of the restructured industry is that the system operator must be isolated from commercial market pressures. At a minimum, a "code of conduct" is required that prevents the system operator from providing preferential treatment for generation or transactions that are owned or sponsored by the system operators company. At a maximum, the system operator can be an independent, non-profit, commercial organization, an Independent System Operator (ISO).

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we outline the scope of issues, challenges and opportunities in the area of real-time security monitoring and control (RTSMC) of power systems in the restructured electricity industry. The counterpart of power system reliability in real-time operations is security—the ability of the power system to withstand contingencies.

The White Paper starts out with an introductory section to explain the framework for RTSMC. The following sections are devoted to (1) the multitude of challenges and opportunities in RTSMC under the unbundled regime; (2) a reexamination of control laws in light of the changing environment and to take advantage of the opportunities from incorporating new technology advances; and (3) possible strategies in the area of analytical and software tools to deal with the many aspects of RTSMC in the restructured environment.

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we define the five most likely scenarios through which distributed energy resources (DER) will gain market acceptance, identify current barriers to development of these markets, and identify the areas of research needed to overcome these barriers.

The White Paper identifies the following areas of research as high priorities to facilitate greater market adoption of DER:

1. Inexpensive, standardized power electronics converters and controls;
2. Islanded (i.e., isolated from the grid) and integrated protection and control schemes;
3. Islanded and integrated real-time MW and voltage regulation for DERs;
4. Islanded and integrated real-time dispatch and control;
5. High-quality power for both islanded and integrated operations;
6. Wide area real-time data communication protocols and infrastructures;
7. Integration of demand-side resources in electricity markets;
8. Independent identification of DER operational requirements; and
9. Field testing of all the above technologies and processes.

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we discuss uncertainties that are not captured in current planning process used by utilities in a regulated environment as well as emerging uncertainties that result uniquely from the restructuring of the electric industry. In latter sections, we identify technologies/methodologies that can be developed and employed to accommodate or manage these uncertainties to ensure reliable electric power. Finally, we briefly discuss market-supplied solutions to planning, operations, and reliability issues.

In its interim report, POST found that the reliability events of the summer of 1999 demonstrated that the necessary operating practices, regulatory policies, and technological tools for assuring an acceptable level of reliability were not yet in place. This report outlines some of the changes needed to address the causes of these events.

Many of the recommendations presented in this report address reforms required to enable restructured markets to fulfill their potential to provide improved reliability. Markets should reflect the value of reliability to energy providers and their customers, and to the broader public interest. Both providers and customers should have opportunities to participate in markets for energy and ancillary services—and to profit from that participation. Modified (or new) institutions are needed to monitor and enforce compliance with reliability standards.

The electric power industry is in the midst of evolutionary change. The reliability events during the summer of 1999 (i.e., outages in New York City, Long Island, New Jersey, the Delmarva [Delaware-Maryland-Virginia] Peninsula, the South-Central States, and Chicago and nonoutage power disturbances in New England and the Mid-Atlantic area) demonstrate that the necessary operating practices, regulatory policies, and technological tools for dealing with the changes are not yet in place to assure an acceptable level of reliability. In a restructured environment, generation technologies and prices are a matter of private choice, yet the reliability of the delivery system benefits everyone. The operation of the electric system is more difficult to coordinate in a competitive environment, where a much larger number of parties are participating.

The Institute of Electrical and Electronics Engineers—United States of America (IEEE-USA) Energy Policy Committee and the Consortium for Electric Reliability Technology Solutions (CERTS) organized a one-day symposium on 24 May 2000 at the Hyatt Regency Hotel in Washington, D.C. with co-sponsorship by Electric Power Research Institute (EPRI) and the U.S. Department of Energy. The Symposium examined the challenges that lie ahead for ensuring reliability as the U.S. electric power system undergoes the most fundamental transformation in its operation since its creation more than 100 years ago.
It explored the perspectives of market participants, system operators, government, and academics on various aspects of reliability—including market operations, system management, industry oversight, and research and development. Held to promote a dialogue between industry stakeholders on issues related to reliability management, the symposium provided the factual backdrop to policymakers for the upcoming debates on reliability and the restructuring of the electric power industry.