The Demand Response Spinning Reserve project is a pioneering demonstration showing that existing utility load-management assets can provide an important electricity system reliability resource known as spinning reserve. Using aggregated demand-side resources to provide spinning reserve as demonstrated in this project will give grid operators at the California Independent System Operator (CA ISO) and Southern California Edison (SCE) a powerful new tool to improve reliability, prevent rolling blackouts, and lower grid operating costs. In the first phase of this demonstration project, we target marketed SCE?s air-conditioning (AC) load-cycling program, called the Summer Discount Plan (SDP), to customers on a single SCE distribution feeder and developed an external website with real-time telemetry for the aggregated loads on this feeder and conducted a large number of short-duration curtailments of participating customers? air-conditioning units to simulate provision of spinning reserve. In this second phase of the demonstration project, we explored four major elements that would be critical for this demonstration to make the transition to a commercial activity: 1. We conducted load curtailments within four geographically distinct feeders to determine the transferability of target marketing approaches and better understand the performance of SCE's load management dispatch system as well as variations in the AC use of SCE?s participating customers; 2. We deployed specialized, near-real-time AC monitoring devices to improve our understanding of the aggregated load curtailments we observe on the feeders; 3. We integrated information provided by the AC monitoring devices with information from SCE's load management dispatch system to measure the time required for each step in the curtailment process; and 4. We established connectivity with the CA ISO to explore the steps involved in responding to CA ISO-initiated requests for dispatch of spinning reserve. The major findings from the second phase of this demonstration are:1. Demand-response resources can provide full response significantly faster than required by NERC and WECC reliability rules. 2. The aggregate impact of demand response from many small, individual sources can be estimated with varying degrees of reliability through analysis of distribution feeder loads. 3. Monitoring individual AC units helps to evaluate the efficacy of the SCE load management dispatch system and better understand AC energy use by participating customers. 4. Monitoring individual AC units provides an independent data source to corroborate the estimates of the magnitude of aggregate load curtailments and gives insight into results from estimation methods that rely solely on distribution feeder data.

An interconnected electric power system is a complex system that must be operated within a safe frequency range in order to reliably maintain the instantaneous balance between generation and load. This is accomplished by ensuring that adequate resources are available to respond to expected and unexpected imbalances and restoring frequency to its scheduled value in order to ensure uninterrupted electric service to customers. Electrical systems must be flexible enough to reliably operate under a variety of "change" scenarios. System planners and operators must understand how other parts of the system change in response to the initial change, and need tools to manage such changes to ensure reliable operation within the scheduled frequency range. This report presents a systematic approach to identifying metrics that are useful for operating and planning a reliable system with increased amounts of variable renewable generation which builds on existing industry practices for frequency control after unexpected loss of a large amount of generation. The report introduces a set of metrics or tools for measuring the adequacy of frequency response within an interconnection. Based on the concept of the frequency nadir, these metrics take advantage of new information gathering and processing capabilities that system operators are developing for wide-area situational awareness. Primary frequency response is the leading metric that will be used by this report to assess the adequacy of primary frequency control reserves necessary to ensure reliable operation. It measures what is needed to arrest frequency decline (i.e., to establish frequency nadir) at a frequency higher than the highest set point for under-frequency load shedding within an interconnection. These metrics can be used to guide the reliable operation of an interconnection under changing circumstances.

The Real Time System Operations (RTSO) 2006-2007 project focused on two parallel technical tasks: (1) Real-Time Applications of Phasors for Monitoring, Alarming and Control; and (2) Real-Time Voltage Security Assessment (RTVSA) Prototype Tool. The overall goal of the phasor applications project was to accelerate adoption and foster greater use of new, more accurate, time-synchronized phasor measurements by conducting research and prototyping applications on California ISO's phasor platform - Real-Time Dynamics Monitoring System (RTDMS) -- that provide previously unavailable information on the dynamic stability of the grid. Feasibility assessment studies were conducted on potential application of this technology for small-signal stability monitoring, validating/improving existing stability nomograms, conducting frequency response analysis, and obtaining real-time sensitivity information on key metrics to assess grid stress. Based on study findings, prototype applications for real-time visualization and alarming, small-signal stability monitoring, measurement based sensitivity analysis and frequency response assessment were developed, factory- and field-tested at the California ISO and at BPA. The goal of the RTVSA project was to provide California ISO with a prototype voltage security assessment tool that runs in real time within California ISO?s new reliability and congestion management system. CERTS conducted a technical assessment of appropriate algorithms, developed a prototype incorporating state-of-art algorithms (such as the continuation power flow, direct method, boundary orbiting method, and hyperplanes) into a framework most suitable for an operations environment. Based on study findings, a functional specification was prepared, which the California ISO has since used to procure a production-quality tool that is now a part of a suite of advanced computational tools that is used by California ISO for reliability and congestion management.

The objective of the CERTS Microgrid Laboratory Test Bed project was to enhance the ease of integrating small energy sources into a microgrid. The project accomplished this objective by developing and demonstrating three advanced techniques, collectively referred to as the CERTS Microgrid concept, that significantly reduce the level of custom field engineering needed to operate microgrids consisting of small generating sources. The techniques comprising the CERTS Microgrid concept are: 1) a method for effecting automatic and seamless transitions between grid-connected and islanded modes of operation; 2) an approach to electrical protection within the microgrid that does not depend on high fault currents; and 3) a method for microgrid control that achieves voltage and frequency stability under islanded conditions without requiring high-speed communications. The techniques were demonstrated at a full-scale test bed built near Columbus, Ohio and operated by American Electric Power. The testing fully confirmed earlier research that had been conducted initially through analytical simulations, then through laboratory emulations, and finally through factory acceptance testing of individual microgrid components. The islanding and resychronization method met all Institute of Electrical and Electronics Engineers 1547 and power quality requirements. The electrical protections system was able to distinguish between normal and faulted operation. The controls were found to be robust and under all conditions, including difficult motor starts. The results from these test are expected to lead to additional testing of enhancements to the basic techniques at the test bed to improve the business case for microgrid technologies, as well to field demonstrations involving microgrids that involve one or mroe of the CERTS Microgrid concepts.

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.

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 g 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. We develop a comprehensive end-use framework for assessing the cost to U.S. electricity consumers of power interruptions and power-quality events (referred to collectively as "reliability events"). The framework expresses these costs as a function of: - Number of customers by type in a region; - Frequency and type of reliability events experienced annually (including both power interruptions and power-quality events) by these customers; - Cost of reliability events; and - Vulnerability of customers to these events. The framework is designed so that its cost estimate can be improved as additional data become available. Using our framework, we estimate that the national cost of power interruptions is about $80 billion annually, based on the best information available in the public domain. However, there are large gaps in and significant uncertainties about the information currently available. Notably, we were not able to develop an estimate of power-quality events. Sensitivity analysis of some of these uncertainties suggests that the total annual cost could range from less than $30 billion to more than $130 billion. Because of this large range and the enormous cost of the decisions that may be based on this estimate, we encourage policy makers, regulators, and industry to jointly under take the comparatively modest-cost improvements needed in the information used to estimate the cost of reliability events. Specific areas for improvement include: coordinated, nationwide collection of updated information on the cost of reliability events; consistent definition and recording of the duration and frequency of reliability events, including power-quality events; and improved information on the costs of and efforts by consumers to reduce their vulnerability to reliability events.