Naperville Smart Grid Initiative Business Case Fundamentals Updated on 9/7/2010 Summary The NGSI program delivers an excellent ROI by increasing network reliability, operational efficiencies, reducing wasted energy, and providing customers the option to use new tools, additional rate plans, and low cost off peak energy to manage their energy costs. Over the past couple of decades, Naperville has invested in its electric grid to support the explosive population growth of the city and to improve overall reliability of the electrical distribution service. The NGSI will leverage this current upgraded infrastructure in creating a state-of-the-art grid that will improve the utility s ability to more efficiently distribute energy and empower customers to choose when they want to consume electricity and how they pay for it. The budget for the three year NSGI program is approximately $22 million. 50 percent of the funds come from a U.S. Department of Energy (DOE) Smart Grid grant a part of the 2009 American Recovery and Reinvestment Act. Naperville s financial obligation is 50% of the total. Naperville will fund the first three years of its financial obligation through 20 year municipal bonds at an interest rate of 4%. Please also note that $9M of the $11M city financial obligation is part of the existing 5 year capital plans for DPU-E. The baseline business case does NOT include the harder to quantify societal benefits, such of increased reliability and reduced carbon emissions. While these benefits are real they have not been included in the financial analysis of the business case. The baseline business case has a positive Net Present Value (NPV) of $31.8 1 million over 15 years and an internal rate of return of 91%. The NSGI program turns cumulative net cash flow positive in the fourth year. The benefits of the NSGI program will come from energy and demand reductions and operational savings by the utility. 2 Reasons for the initiative There are three primary drivers for this project: Macro and regional trends: Studies from the DOE suggest that over the next 25 years electricity bills will increase by 50 percent due to population growth and technical demands. Additionally, the demand for renewable energy is growing, and the current grid infrastructure is not capable of supporting these future needs. It is clear that as the cost of power will rise over time, energy conservation and peak demand decreases will be key to controlling our energy bills. 1 This is based on net present value of benefits minus costs over 15 years with 4.24% discount rate. 2 Consumption is defined as the total amount of electricity used. Demand is defined as the immediate rate of that consumption.
Shift in power costs: In 2011, Naperville will enter a new long term power purchasing contract with the Illinois Municipal Electric Agency (IMEA). Since Naperville does not generate its own power it must purchase its power. IMEA's primary function is to provide wholesale electricity to its municipal utility participants. IMEA is made up of 33 electric systems served under a full-requirements wholesale purchasing contract and its goal is to keep power costs low and to be insulated from the high prices that are increasingly common in the short-term power market. With this contract, it will cost the city less money for purchased power in the off-peak periods and more money for purchased power during peak periods. A variable cost for energy due to the peak demand charge, impacts the costs of providing energy to end customers. Finding a way to manage peak demand of electricity will help control the cost of providing service to end customers. Even small changes during these peak periods will significantly impact the overall purchased power costs. Efficiencies applied to power distribution will also reduce peak demand and energy consumption and will help drive down the overall cost to the customer. State of the grid: While Naperville s electric grid delivers very reliable electric services to its customers, it still needs additional improvements to support new technologies such as plug-in electric vehicles and home area networks. This document will further itemize the components that are contained within the Naperville Smart Grid Initiative. Goals and Objectives The key goals of the NSGI Program are to reduce peak demand, reduce energy consumption, increase electric service reliability, and provide customers choice. To achieve these goals, there are several objectives that must be accomplished: Improve the efficiency of the power delivery of the electric distribution system (electric grid). Provide solutions for commercial, residential, and industrial customers to better monitor and control their peak demand and energy consumption. Improve the utility s ability to measure power quality, detect outages throughout the distribution system and to respond accordingly - increasing efficiency in utility operations. Meeting these objectives will transform the way power is distributed to customers and create a more reliable network. In addition to better energy management at the network level, the NSGI Program will empower Naperville customers with choices on how and when they consume power, how they pay for the electricity they use, as well as choices of energy sources (such as solar and wind). These rate choices along with the customer feedback tools will provide customers with the tools to control their energy bills that did not previously exist. Project Details Funding The total cost for the Naperville Smart Grid Initiative is approximately $22 million, which will be split between the DOE and the City of Naperville. In 2009, the DOE issued Smart Grid Investment Grants (SGIG) through the 2009 American Recovery and Reinvestment Act (ARRA 2009). The City s Department of Public Utilities - Electric (DPU-E) submitted a grant application and was awarded federal funds to drive its Smart Grid related projects to completion. With municipal and federal financing 2
secured, implementation of the NSGI Program began in January 2010, with all funding-related initiatives slated for completion by the end of Q1 2013. DPU-E had planned to make these improvements over time, but the opportunity to receive federal funds provided the city with an opportunity to accelerate this investment at a significantly lower cost. For its share, Naperville s funding sources include the sale of municipal bonds as well as the reprioritization of associated DPU-E planned capital investments from 2011-2015 to 2010-2012 (fiscal years). Benefits Naperville expects a net benefit of $46.2 2 million net present value (NPV) from this initiative. The following table lists the project benefit categories and the forecasted return on investment (ROI) over a 15 year period. Please refer to the Project Review and Approval section of this document for details on how the benefit values were developed and validated. Benefit Category Description 15-Year Benefit ($ millions) 3 Operational Benefits (Benefit Source = Utility) Reductions of planned expenses by DPU-E include reduced meter reading cost and improved meter reading accuracy. The benefits are realized through deployment of the smart grid components and do not require any change in $6.9 Distribution Efficiency Energy and Demand Reduction Benefits (Benefit Source = Utility) Customer Energy Management (CEM) Benefits (Benefit Source = Customer Choice) behavior by the end customer. Reduction of energy demand and consumption 3 due to improvements in the distribution of electricity in the network. These benefits are realized through the deployment of the Conservation Voltage Reduction (CVR) application and do not require any change in behavior by the end customer. Benefits gained through reduced energy demand and consumption 4 due to the end customer s improved management of their energy consumption. This category of benefit does require adoption by the energy users. $19.3 $20 Societal Benefits 5 (Benefit Source = increased reliability and reduced carbon emissions) Total 15-Year Hard Benefits 4 Customer benefits directly related to improved service reliability from distribution automation (DA) and substation automation (SA), as well as lower green house gas emissions 5 due to energy reductions. Note: The societal benefits are not included in the baseline NSGI business case. The Hard Benefits include the operational benefits and the distribution efficiency energy and demand reduction benefits. $16.4 $46.2 2 Based on net present value of costs minus the net present value of benefits, using a discount rate of 4.24% 4 Societal Benefits are not included in the baseline business case and are shown for information only. 5 Green house gas emission reduction was estimated using numbers from the IMEA and the Environmental Protection Agency based on reduced consumption. 3
Smart Grid Initiative Program Components and Budgetary Allowances The overall NSGI Program is segmented into seven separate projects. Each project includes the hardware, software, and labor to complete the tasks. The table below lists each of the individual projects and the associated budgetary allowance. Please refer to the Project Assets and Technologies section of this document for descriptions of the hardware and technology implemented in each project. Project # Project Components Description Budgetary Allowance 1 Program Management Office (PMO) Reporting Change Management Costs for program management oversight, reporting obligations to the DOE, and strategy for change management execution. 2 Customer education and outreach Support the education of customers as well as solicit feedback from customers on needs and solution performance. 3 Advanced Metering Infrastructure (AMI) Meter Data Management System (MDMS) Load Control Management System (LCMS) Home Area Network (HAN) 4 Customer Usage Feedback Demand Side Management/Demand Response Programs 5 Substation Automation (SA) Distribution Automation (DA) Supervisory Control and Data Acquisition (SCADA) Telecom 6 Outage Management Systems (OMS) Distribution Management Systems (DMS) Workforce Management Systems (WFMS) Naperville Asset Management and Project Portfolio Management Systems (NAMS/PPMS) 7 System Integration and System Acceptance Technologies that help gather, measure, and analyze energy usage data and help consumers determine how best to manage energy consumption. Processes and technologies for presenting energy usage information and NSGI Program data to end customers. Includes customer and utility eportal and customer usage feedback support. Technologies that allow for data collection and remote control of the power grid that will reduce outage durations and alleviate overload conditions. Technologies that allow for improved outage management, more efficient use of information by support systems, and better management of utility assets and services. Costs of integrating all necessary components of the project and ensuring proper acceptance testing. $ 3,139,240 $ 500,000 $ 13,605,551 $ 1,029,847 $ 1,597,153 $ 1,256,584 $ 859,845 Total Allowance $ 21,988,220 4
The chart below outlines a 15 year timeline of when costs and benefits will be realized during the NSGI Program. The bulk of the costs will be from capital spending, the majority of which will be spent within the first 3 years. Benefits are expected to grow steadily each year after implementation. The cumulative cash flow break even is expected to happen in year 4. This spending and benefits chart is based on borrowing the $11M of Naperville s financial commitment through 20 year municipal bonds at 4% interest to fund the capital in each of the first three years. $10,000 Projected Costs & Benefits by Year (Revised 8/23/2010) $8,000 $6,000 $ in 000s $4,000 $2,000 $- 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 $(2,000) Capital and Debt Service (Less Grant Match) Incremental O&M Costs Operational Benefits Energy & Demand Benefits associated with Distribution Efficiency Customer Energy Management Benefits Project Review and Approval Process In mid-2009 the City of Naperville engaged West Monroe Partners, an independent business and technology consulting firm, to help with the creation of a Smart Grid strategy business case and deployment plan. Together, Naperville and West Monroe Partners developed the Naperville Smart Grid Business Case. This business case and Smart Grid roadmap was the foundation to develop the DPU-E SGIG application, which was submitted to the DOE for review and approval. Out of more than 500 applicants, Naperville s proposal was one of 100 approved, and the only utility to receive SGIG funding in Illinois. 5
In early 2010, West Monroe Partners retained Burns and McDonnell, a third party consulting firm, to conduct an independent evaluation of the Naperville Smart Grid Business Case. Following the independent evaluation, the City of Naperville and West Monroe Partners used the Burns and McDonnell recommendations to improve their original Naperville Smart Grid Business Case, which in turn was used to compose a simplified version, NSGI Program Business Case Fundamentals (this document). Project Assets and Technologies In order to meet the stated goals and objectives, the following technologies will be implemented as part of the NSGI Program: Advanced Metering Infrastructure (AMI) The Advanced Metering Infrastructure (AMI) system uses smart meters and the related hardware, software, and communications tools to gather, measure, and analyze energy usage data. The AMI system allows DPU-E to better understand and monitor the complete electrical system up to the meter - which will enable instant notification of outage, faster recovery time, analysis of power quality and tailoring of voltage to provide more consistent and quality power to every customer. Meter Data Management System (MDMS) The Meter Data Management System (MDMS) is an IT system that the utility uses to manage large volumes of meter data generated by the AMI system. The MDMS system will help the utility detect and restore outages quickly, improve reliability of electric distribution, create more accurate energy supply and demand forecasts, and provide revenue stability. Load Control Management System (LCMS) The Load Control Management System (LCMS) is an IT system that the utility uses to tie the AMI and MDMS systems to the Home Area Network (HAN) devices. The LCMS system enables the customer to voluntarily participate in a Demand Side Management/Demand Response program. If a homeowner opts into these programs, DPU-E will be able to cycle the specified devices on and off during high-load or emergency conditions which will effectively reduce the customer s power consumption during the most expensive times of the day, reducing their energy bill. Home Area Network (HAN) The Home Area Network (HAN) connects the DPU-E smart meter to major power-consuming devices in the home or business, devices including air conditioners, electric ovens, refrigerators, etc. The program will enable technology for the interconnectivity of Programmable Control Thermostats (PCT), Load Control Relays (LCR), and Home Energy Devices (HEDs) which will provide homeowners with tools to help them determine how and when to shift their consumption in a way that will maximize efficiency and minimize cost. A study by the American Council for an Energy-Efficient Economy shows consumers can cut consumption by 4 to 12 percent due to the awareness that is enabled by incorporating an HED and other tools in the home. 6
Demand Side Management (DSM) and Demand Response (DR) Demand Side Management (DSM) and Demand Response (DR) is a set of programs that benefit both the utility and the customers and aim to reduce energy demand and consumption. These programs enable the customer to manage their energy usage. These are customer-focused programs that are sponsored by the utility that focus on energy efficiency and alternative pricing and are designed to aid customers in reducing their energy usage and ultimately save money. Demand Side Management programs are utility-initiated programs that are designed to lower demand on the electric distribution system (electric grid). DSM programs are based on customer adoption and participation. Demand Response programs are those that allow customers take action to reduce demand such as Naperville s current Voluntary Load Reduction (VLR) program. As such, call center support, online resources, and other customer service channels will provide customers with personalized energy consumption data to allow them the option to modify energy consumption. Substation and Distribution Automation (SA/DA), SCADA and Telecommunications Substation Automation (SA) enables data collection, control, and automation of the DPU-E electric substations. Distribution Automation (DA) allows for data collection, control, and automated switching of electric distribution feeders to reduce outage durations and alleviate overloaded conditions. Upgrades made to the network infrastructure will allow for real-time Supervisory Control and Data Acquisition (SCADA) monitoring; improving communication flow and allowing for remote configuration management and performance management reporting. Outage Management Systems (OMS) This system provides additional operational and service efficiencies to the utility. The Outage Management System (OMS) identifies outage conditions so that power can be re-routed around the outage and restored to Naperville customers more quickly and efficiently. The new OMS will receive and process various inputs for outage analysis, identify locations of outages, manage crews, allow dynamic circuit model changes, maintain historical data, and provide operational and planning analysis and reports. Distribution Management Systems (DMS) The Distribution Management System (DMS) obtains data from various other utility systems and assists in the management and optimization of the electric distribution system (electric grid). This will improve the electric grid through increased reliability, electric load management, and maximization of work coordination. Workforce Management Systems (WFMS) A Workforce Management System (WFMS) solution allows for the centralized management of assets and services for utility employees to proactively respond to service calls. This system provides the tools to increase the visibility of workforce and workload decisions and provide improved customer service through faster response times. Naperville Asset Management and Project Portfolio Management Systems (NAMS/PPMS) 7
Naperville Asset Management and Project Portfolio Management Systems (NAMS/PPMS) is a combination of components capable of data collection, project portfolio management, and project workflow management. The overall system will be able to capture condition information from existing utility assets through inspections and testing. It will facilitate the prioritization (based on both technical and cost metrics), management, and performance of jobs and assets in order to continuously provide the expected level of service. Program Management Office (PMO), Change Management and Reporting The Program Management Office (PMO) oversees the implementation of project components and ensures that tasks are completed on-time and within budget. This includes Change Management and reporting. Change Management is the term for the restructuring of Naperville s business policies and procedures in order to best accommodate and experience the technical modifications provided by the NSGI Program. As a condition to participating in an ARRA grant, Naperville must file frequent and detailed reports regarding their progress and spending to the DOE and OMB (Office of Management and Budget). Customer Outreach and Education Customer Outreach and Education Initiatives will utilize different processes and technologies to ensure that consumers are aware of their rights, options, energy usage, and other information as related to the NSGI Program. eportal A web-based customer portal will provide customers with an interface by which they can select rate programs, monitor their daily energy consumption, opt-in to DPU-E programs, register HAN devices, receive Naperville and DPU-E news and notices, and manage their communication preferences as related to their individual energy management. System Integration and System Acceptance System Integration is the IT activities required to essentially make all of the required old and new Naperville and DPU-E IT systems work together based on the pre-established technical requirements. Systems integration testing will investigate the proper technical implementation of the integrations. System acceptance testing will utilize use cases to mimic actual production operations and assess the production readiness of the new business processes, systems and interfaces. Most, if not all, system acceptance tests will include functionality or data where two or more systems are involved (for example, meter to cash testing). Testing on individual systems (for example, AMI), will be conducted as part of their system implementations and are considered sub-system testing. Conservation Voltage Reduction (CVR) Conservation Voltage Reduction (CVR) focuses on optimizing the voltage within the electric distribution system. It allows for the reduction of energy consumption through adjustments to the electric distribution system that result in slight reductions to customer voltage levels. The resulting voltage levels, while within the DPU-E guidelines and within the tolerances of customer devices, will provide for energy and demand savings. CVR is not dependent upon a change in consumer behavior, but rather leverages the grid 8
investments made by Naperville, as well as the new AMI network. The new AMI network provides customer voltage information for the first time to DPU-E, making this very beneficial yet simple adjustment possible. Conclusion The NGSI Program is a mutually beneficial initiative that will allow the City of Naperville to better manage one of its most vital assets and serve its residents in a more efficient and reliable manner as well as provide their residents the option to better manage their electric usage and potentially save money on their electric bill. With the help of implementing proven technology, customer-centric tools, and a focus on the customer s needs, the City of Naperville will be working for the next three years to make Smart Grid a reality. 9