Annex A Metrics for the Smart Grid System Report Table of Contents Introduction ........................................................................................................................................... A.1 Metric #1: The Fraction of Customers and Total Load Served by Real-Time Pricing, Critical Peak Pricing, and Time-of-Use Pricing ........................................................................................ A.2 Metric #2: Real-Time System Operations Data Sharing ...................................................................... A.9 Metric #3: Standard Distributed Resource Connection Policies .......................................................... A.18 Metric #4: Regulatory Recovery for Smart Grid Investments ............................................................. A.23 Metric #5: Load Participation .............................................................................................................. A.28 Metric #6: Load Served by MicroGrids ............................................................................................... A.35 Metric #7: Grid-Connected Distributed Generation and Storage ........................................................ A.41 Metric #8: Market Penetration of Electric Vehicles and Plug-In Hybrid Electric Vehicles ................ A.49 Metric #9: Grid-Responsive, Non-Generating Demand-Side Equipment ........................................... A.56 Metric #10: Transmission and Distribution Reliability ....................................................................... A.62 Metric #11: Transmission and Distribution Automation ..................................................................... A.69 Metric #12: Advanced Meters.............................................................................................................. A.75 Metric #13: Advanced Measurement Systems ..................................................................................... A.84 Metric #14: Capacity Factors ............................................................................................................... A.91 Metric #15: Generation, Transmission, and Distribution Efficiency ................................................... A.97 Metric #16: Dynamic Line Ratings ...................................................................................................... A.103 Metric #17: Customer Complaints regarding Power Quality Issues .................................................... A.107 Metric #18: Cyber Security .................................................................................................................. A.112 Metric #19: Open Architecture/Standards ........................................................................................... A.118 Metric #20: Venture Capital Investment in Smart Grid Startup Companies ....................................... A.124 A.iii Annex A Metrics for the Smart Grid System Report Introduction This annex presents papers covering each of the 20 metrics identified in Section 2.1. These metric papers were prepared in advance of the main body of the report and collectively form its informational backbone. The list of metrics is derived from the material developed at the Smart Grid Implementation Workshop. The objective of the metric development process was to distill the best ideas into a small number of metrics with a reasonable chance of measurement and assessment. The metrics examined in this annex are of two types: build metrics that describe attributes that are built in support of the smart grid, and value metrics that describe the value that may derive from achieving a smart grid. Build metrics generally lead the value that is eventually provided, while value metrics generally lag in reflecting the contributions that accrue from implementations. While build metrics tend to be quantifiable, value metrics can be influenced by many developments and therefore generally require more qualifying discussion. Both types are important in describing the status of smart grid implementation. Each metric paper is divided into five sections as outlined below: o Introduction and Background: A brief introduction to the concepts addressed by the metric, including an overview of relevant issues. o Description of Metric and Measurable Elements: An identification and description of the metric being measured. o Deployment Trends and Projections: The current status of the metric, analysis of trends and projections, identification of relevant stakeholders and their relationship to the smart grid, and assessment of regional influences on smart grid deployment. o Challenges to Deployment: An overview of the technical, business, and financial challenges to smart grid deployment. o Metric Recommendations: Recommendations to consider when preparing the next Smart Grid System Report to Congress. The content in these metric papers are reproduced in sections of the main body of the report. References embedded in the report are designed to enable readers to trace content back to its original source here in Annex A. A.1 Metric #1: The Fraction of Customers and Total Load Served by Real-Time Pricing, Critical Peak Pricing, and Time-of-Use Pricing M.1.1.0 Introduction and Background Historically, utilities have set prices on a flat- rate basis, unaffected by time of energy use, by the time-varying cost to the utility to supply the energy, or by time-varying power demand. The flat-rate system, while simple to understand and communicate to customers, does invariably lead to overconsumption of energy during peak periods when the cost to supply the power is at its highest point. Numerous studies have, in recent years, documented the pitfalls associated with flat-rate systems, and quantified the benefits associated with more dynamic pricing that varies based on the time of day or cost of power. One such study, which examined a number of pricing policies varying from time-of-use (TOU) pricing to critical-peak-period (CPP) pricing, found that these pricing policies could save the average customer $3.94-$8.02 monthly depending on the pricing system implemented.1 There are three principal pricing or tariff types covered in this section, as presented in Figure M.1.1.2 Under a TOU tariff, prices are differentiated based solely on a peak- versus off- peak-period designation, with prices set higher during peak periods. TOU pricing requires smart grid technology—interval usage measurements found in advanced metering infrastructure (AMI)— and might be viewed as an intermediate step towards a more dynamic real-time pricing (RTP) tariff. Figure M.1.1. Examples of Dynamic Pricing Some TOU tariffs include a CPP tariff, where the Tariff Structures 1Faruqui A and L Wood. 2008. Quantifying the Benefits of Dynamic Pricing in the Mass Market. Edison Electric Institute. Washington, D.C. 2Federal Energy Regulatory Commission (FERC). December, 2008. Assessment of Demand Response and Advanced Metering. FERC, Washington, D.C. A.2 higher critical peak price is restricted to a small number of hours (e.g., 100 of 8,760) each year, with the peak price being set at a much higher level relative to normal conditions. Utilities may or may not provide advanced notice of impending CPP periods. Under RTP, at hourly or even shorter intervals, prices vary based on the day-of (real time) or day-ahead cost of power to the utility. Prices fluctuate throughout the day with the highest prices set during peak periods. RTP tariffs are the most dynamic of the three pricing structures and are therefore most dynamically responsive to peak-period consumption and energy costs. M.1.2.0 Description of Metric and Measurable Elements (Metric 1.a) the fraction of customers served by RTP, CPP, and TOU tariffs. (Metric 1.b) the fraction of load served by RTP, CPP, and TOU tariffs. M.1.3.0 Deployment Trends and Projections RTP tariffs have historically been offered on either a voluntary or default (mandatory) basis, and only to industrial and large commercial accounts. To date, more than 70 utilities have offered voluntary RTP tariffs on either a temporary pilot or permanent basis. As of 2003, however, there were 43 tariffs offered on a voluntary basis, serving 2,700 customers collectively responsible for 11,000 MW of peak demand.3 As of 2005, default RTP service was approved for implementation in five states – New Jersey, Maryland, Pennsylvania, New York, and Illinois. Within those states, default RTP service is in place for the largest commercial and industrial customers of ten investor-owned utilities (IOUs). Furthermore, default RTP service is proposed or planned for an additional 16 IOUs. The default enrollment in the ten participating utilities has reached nearly 1,000 MW.4 When combined with the estimated load served under voluntary RTP tariffs, total RTP deployment reached approximately 12,000 MW, or 1.1% of total national net winter generating capacity. The Federal Energy Regulatory Commission (FERC) conducted an extensive survey of demand- response and advanced-metering initiatives in 2008. The FERC survey was distributed to 3,407 organizations in all 50 states. In total, 100 utilities that responded to the survey reported offering some form of an RTP tariff to enrolled customers, as compared to 60 in 2006 (Table M.1.1). FERC also found through its 2008 survey that 315 utilities nationwide offered TOU rates, compared to 366 in 2006. In those participating utilities, approximately 1.3 million electricity consumers were signed up for TOU tariffs, representing