Using electricity customer profiles to combat GHG emissions: New evidence from ComEd AMI data

This first-of-its kind study categorizes the residential customer base of Illinois’ largest electric utility, Commonwealth Edison, into slices of customer-usage profiles to determine their marginal Greenhouse Gas emissions for the period 2016−2018. The analysis utilizes anonymous energy-usage data from Advanced Metering Infrastructure, PJM marginal emissions data, and demographic data from the U.S. Census Bureau’s American Community Survey of 2017. Using a machine-learning algorithm called k-means clustering, the analysis identifies distinct usage patterns of residential customers and once again proves the value of access to anonymous AMI data. Even more importantly, the results provide new evidence to inform regulators, consumer advocates, policymakers and utilities on how best to customize energy efficiency, weatherization, customer education, and demand response programs for maximum benefit.     

Single-phase voltage regulators and three-phase systems

Voltage regulators are applied on distribution systems to control the voltage delivered to customers within acceptable industry standards. Concerns about the quality of electric power delivered to customers by electric utility companies have raised the level of awareness of high- and low-voltage conditions at customer facilities. Normally occurring voltage drops through lines and transformers vary with the load level on the system. Voltage regulators, when properly applied, can compensate for these voltage drops and keep customer voltage within proper limits. Single-phase voltage regulators can be applied on three-phase systems in a variety of ways, including grounded-wye, open-wye, closed-delta, and open-delta. The capabilities of the regulator systems are affected by the system design. In this article, the authors review the characteristics of the closed-delta and wye applications, and discuss the advantages and disadvantages of each application scheme. The impact of the regulator connection on overcurrent protection is also reviewed     

Quantifying Reliability and Service Quality for Distribution Systems

Reliability indices for distribution systems are used by utilities and regulators to benchmark performance and prioritize investments in projects to improve performance. However, there can be many variations in the methods used to describe reliability levels, and the indices used may not be the best measures of system performance in terms of the impacts on customers. This paper describes the concept of a "service quality index" that can be used to characterize system performance in a manner that is more appropriate for customers, taking into account customer quality and reliability requirements and expectations     

Default service pricing – The flaw and the fix: Current pricing practices allow utilities to maintain market dominance in deregulated markets

Utility default service has been priced incorrectly for two decades. Incumbent utilities serving as default service providers for both electricity and gas allocate few to no “costs to serve” to default service rates. The indirect costs not allocated include billing, customer care, enrollments, metering, and other overhead and add up to billions of dollars annually. These costs are paid in distribution rates. The resulting rate for utility-provided default service is a below-market price, allowing the utilities to maintain dominant market positions in the retail markets for residential and small commercial customers. This pricing practice distorts the relevant retail electric and gas markets and harms customers and the markets. NARUC cost allocation guidelines advocate that the cost of utility resources used in the provision of default service should be allocated to that service. This paper presents a Default Service Equalization Adjustment Mechanism (“D-SEAM”) that when deployed properly, will provide the default service utilities with a tool to allocate an appropriate amount of costs to default service rates and then adjust that allocation on a monthly basis to ensure the distribution utility is made whole financially as customers migrate off of default service. Without an appropriate allocation of cost to default service, incumbent utilities will maintain a dominant market position in the retail markets for residential and small commercial customers as a result of the significant subsidy provided by the distribution rates. Utilities should adopt, and/or the regulators should compel the adoption of a complete and appropriate allocation of costs to default service. It is only with this allocation that customers will be able to reasonably compare market offerings.     

Institutional competition protects consumers: Public power vs. private power

The historical competition between public power and private power shows that retail customers have chosen the former to reduce costs and improve customer service. Research also shows that publicly owned utilities employ cost-minimizing algorithms, and that federal and state regulators favor the interests of investors over those of customers, undermining their obligation to protect consumer welfare. Institutional options matter and should be strongly encouraged.     

Power to the prosumer: A transformative utility rate reform proposal that is fair and efficient

There is a continuing clash between utilities and proponents of distributed generation, particularly rooftop solar. Generation intermittency, zero-marginal cost energy, and net metering policies associated with solar power make planning, operations, and pricing difficult for utilities. Customers without solar are increasingly concerned they are footing an increasingly larger share of grid costs, while solar customers feel they are not receiving credit for lowering costs for the utility. These pricing issues are caused by an archaic rate structure. We propose that utilities introduce cost-causative rates applied to all customers and adopt transitional methodologies to make a smooth transition between the old and proposed rate structures. Once fully in-place, cost-causative rates will empower customers to increase their own savings while simultaneously reducing costs for others.     

Rate design for a decarbonizing grid

The Western U.S. electric grid has undergone vast changes since the pre-renewables era. For example, renewables now comprise nearly 30% of California’s electric supply portfolio, and recent CA legislation mandates 50% renewables by 2030. As a consequence, intra-day variation in hourly net loads is rapidly steepening, as shown by the California Independent System Operator (CAISO)’s now famous ‘Duck Curve”. In 2015, CAISO recommended a four-season TOU pricing period design, with peak hours between 4?PM and 9?PM on summer weekdays, and a “super-off-peak” period in spring mid-day hours. We present an aggressive four-season time-of-use (TOU) rate design based on CAISO’s recommended TOU periods, and some illustrative impacts of implementing such TOU rates.In Western U.S. energy markets, high wholesale prices generally correspond to high marginal carbon emissions, and conversely. Properly designed TOU rates can help reduce GHG emissions by discouraging energy use during times of high marginal carbon emissions. However, demand charges, a feature of many commercial rate designs, can negate the benefits of TOU rates if applied during off-peak hours. We show that overuse of non-coincident demand charges can discourage customer investments that would benefit both the customer and the grid if rates were correctly aligned with cost. We recommend the following pricing strategies to support long-term efforts toward decarbonization of the electric grid: (1) More widespread use of aggressive 3- or 4-season TOU rates (or RTP where feasible); and (2) Reduced dependence on demand charges that apply during off-peak hours. Widespread utilization of retail rates that are aligned with temporal variation in carbon intensity, by both residential and nonresidential customers, is essential, for achievement of decarbonization goals.

Designing incentive compatible contracts for effective demandmanagement

Demand relief from customers can help a utility (or any “load serving entity”) solve a variety of problems. There exist all sorts of different demand management programs that utilities use. A critical issue is the incentive paid to the customer to participate in demand management programs and provide load relief. The utility has to design cost effective yet attractive demand management contracts. The main goal is to get load relief when needed, and to do so in a cost effective way. Customers sign up for programs when the benefits they derive in the form of up front payments, demand discounts and interruption payments exceed their cost of interruption. In order to design such contracts, mechanism design with the revelation principle is adopted from game theory and applied to the interaction between a utility and its customers. The idea behind mechanism design is to design an incentive structure that encourages customers to sign up for the right contract and reveal their true value of power (and thus, the value of power interruptibility)     

Electric re-regulation impact

The deregulation or re-regulation of the electric utility is rapidly coming to pass. Historically, regulators created a monopoly that stymied creativity, technology and economic viability. A new, competitive electric utility industry can be expected to eventually provide greater service, at a lower cost. Any new regulations which are proposed must deal both with compensating existing utilities for decisions made under the old system, and with allowing organizations to make new decisions which will benefit both them and the customer     

Interruption costs of service sector electricity customers,a hybrid approach

A power outage brings in economic losses for both the customers and the utilities. Studying these unwanted events and making solid predictions about the outcomes of the interruptions has been an attractive area of interest for the researchers for the last couple of decades. By making use of a customer survey study conducted in Finland, this paper benefits from both the reported cost data collected from customers and from the analytical data that are available and then presents a new hybrid approach to estimate the customer interruption costs of service sector customer segment. Making use of Value Added information of the customers is a common practice for the cost normalization purposes. This paper verifies the approach by comparing the findings of the customer survey and the econometric model suggested here. This study is a unique source in terms of providing a reliable, easy to apply, and a straightforward model for calculating the economic impacts of power outages.     

Unbundling reliability: Lessons from the telecom industry

Electric utility customers are seeking increased reliability and resilience. Evolving distributed energy and grid modernization technologies can provide customers with new self-supply options, but regulatory issues are holding back their full deployment. We examine microgrid projects to identify causes of regulatory resistance. Then we examine how telecom utilities, faced with similar challenges, responded by offering customers new, regulator-approved premium reliability services. Finally, we offer insights from telecom precedents that may be transferable to electric utilities.     

Current practices and customer value-based distribution system reliability planning

Among the major issues facing utilities in today's competitive electricity market is the pressure to hold the line on rates and provide electricity with adequate quality and reliability. Utilities are increasingly recognizing that the level of supply reliability planned and designed into a system has to evolve away from levels determined basically on a technical framework using deterministic criteria, and toward a balance between minimizing costs and achieving a sustainable level of customer complaints. Assessment of the cost of maintaining a certain level of supply reliability or making incremental changes therein must include not only the utility's cost of providing such reliability and the potential revenue losses during outages, but also the interruption costs incurred by the affected customers during utility power outages. Such a cost-benefit analysis constitutes the focal point of the value-based reliability planning. Value-based reliability planning provides a rational and consistent framework for answering the fundamental economic question of how much reliability is adequate from the customer perspective and where a utility should spend its reliability dollars to optimize efficiency and satisfy customers' electricity requirements at the lowest cost. Costs to customers associated with varying levels of service reliability are significant factors that cannot be ignored. Explicit considerations of these customer interruption costs in developing supply reliability targets and in evaluating alternate proposals for network upgrade, maintenance, and system design must, therefore, be included in system planning and design process. The paper provides a brief overview of current deterministic planning practices in utility distribution system planning, and introduces a probabilistic customer value-based approach to alternate feed requirements planning for overhead distribution networks.     

Value of service reliability

The authors present the value of service (VOS) reliability evaluation approach, which explicitly incorporates into the planning process customer choices regarding reliability `worth' and service costs. Using the least-cost planning framework and taking advantage of the recent advances in the quantification of outage costs, this approach determines the optimal level of reliability for the utility and its customers. The approach considers system operational measures-the so-called emergency actions-that the operators invoke in times of dwindling reserves. Information on customer outage costs associated with such actions is incorporated using a probabilistic framework. This approach permits utilities to plan for levels of reliability commensurate with the customers' willingness to pay. The application of this methodology to planning problems is discussed. Numerical results for a large utility are presented     

Evaluating DSM: can an engineer count on it? A short note papersummarizing a panel session at the July 1992 summer power meeting

There is an increasing interest in demand-side management (DSM) by utilities and regulators throughout the USA. With this interest, there is an increasing need for DSM evaluation. Regulators expect utility engineers to use least cost planning and integrated resource planning approaches to adjust their generation capacity plans to reflect DSM. Increasingly, utilities are considering DSM to affect their T&D capacity plans. However, major utility DSM programs are less than a decade old. This leaves many utility engineers uneasy. How do they know that DSM will be there when they really need it? To verify and improve the contribution of DSM programs, utility analysts have developed a set of methodologies and procedures for evaluating DSM. The purpose of this panel session was to review these state of the art evaluations and the lessons learned from them so far. The authors explore the differences inherent in evaluating DSM at the T&D level versus the generation level, and review DSM's persistence and reliability in the residential, commercial, and industrial sectors     

Transmission crediting: a plea for subsidies disguised as the linchpin of regional transmission planning

Arguments that FERC's decisions on credits for transmission facilities owned by network customers will chill the development of a regional grid simply are variations on the theme that transmission owning utilities should underwrite the cost of smaller utilities.     

System reliability worth assessment at a midwest utility—survey results for residential customers

This paper presents the overall results of a residential customer survey conducted in service areas of MidAmerican Energy Company, a Midwest utility. A similar survey was conducted concurrently in the industrial, commercial and institutional sectors and the survey results are presented in a companion paper. The results of this study are compared with the results of other studies performed in the high cost areas of the US east and west coasts. This is the first ever study of this nature performed for the residential customers in the US Midwest region. Methodological differences in the study design compared to coastal surveys are discussed. Customer survey costing techniques can be categorized into three main groups: contingent valuation techniques, direct costing techniques and indirect costing techniques. Most customer surveys conducted by different organizations in the last two decades used a combination of all three techniques. The selection of a technique is mainly dependent on the type of customer being surveyed. In this MidAmerican study, contingent valuation techniques and an indirect costing technique have been used, as most consequences of power outages to residential users are related to inconvenience or disruption of housekeeping and leisure activities that are intangible in nature. The major contribution of this paper is that particulars of Midwest residential customers compared to residential customers of coastal utilities are noted and customer responses on power quality issues that are important to customers are summarized.     

Power flow congestion relief by using customer‐side energy storage systems

In recent years, energy storage systems have increasingly been expected as a means of load leveling of the annual load factor. Of course there is an effect of installing the energy storage systems at the substation. But some customers operate their storage system in an integrated way and it also has an effect of increasing the load factor. In this paper the authors proposed that the energy storage systems on the customer side be used for congestion relief on transmission networks. However, it is not clear which kind of customer has the effect of relieving transmission line congestion. First, this paper assumes the authors determine the optimal configuration of energy equipment including energy storage systems. We propose a new contract whereby electric utility subsidizes a part of the entrance cost of the energy storage systems and customers change the output pattern of energy storage according to the request of the electric utility. This paper evaluates the possibility that the contract gives merit to both the electric utility and the customer. © 2006 Wiley Periodicals, Inc. Electr Eng Jpn, 158(1): 36–45, 2007; Published online in Wiley InterScience ( www.interscience.wiley.com ). DOI 10.1002/eej.20299     

The effect of smart meter penetration on dynamic electricity pricing: Evidence from the United States

A successful grid modernization comprises not only the deployment of new energy infrastructure and technologies, but also the utilization of these technologies to promote modern energy services and active consumer engagement. As an enabling technology in smart grids, advanced metering infrastructure (AMI) has been rapidly deployed in the U.S. By the end of 2016, almost half of all electricity consumers have AMI meters with two-way communication capability. While many have examined the driving forces for smart meter technology diffusion, there has been limited empirical evidence on the actual utilization of smart meters in modern energy services. To fill this research gap, this paper explores how electric utilities in the U.S. are leveraging AMI meter installations to implement dynamic pricing programs. A cross-sectional dataset for 582 electric utilities in the U.S. is constructed based on the EIA 861 form “Annual Electric Power Industry Report” from the year 2016. A fractional response regression model is estimated, and results show that a ten-percentage increase in smart meter penetration is associated with an average of 0.56 percentage increase in customer participation in dynamic pricing programs. The estimated effect of smart meters on dynamic pricing programs is relatively small, given the magnitude of capital investment and the scale of smart meter market penetration in the U.S. Future smart grid policies in the U.S. may gradually move away from public investment in AMI roll out and shift to supportive policies that facilitate the implementation and use of AMI to realize the full benefits of smart grid.     

Fast tripping of utility breakers and industrial load interruptions

Some industries are very sensitive to electric power interruptions and voltage sags, which are a normal consequence of the utility fault-clearing process. Typically, US utilities will try once or twice to clear faults without blowing any tap fuses, which would require dispatching a trouble crew to replace. To reduce complaints and to improve power quality for critical customers with high economic impact of interruptions, some utilities have been eliminating fuse-saving practices on feeder breakers and reclosers. The impact on overall reliability and the number of interruptions is evaluated based on distribution feeder power quality data. Some degradation in overall reliability can be expected, but this can be minimized with judicious placement of line reclosers. Critical customers can expect a significant reduction in the number of interruptions. A value-based economic analysis, including both utility and customer costs, shows that the practice has a high overall benefit-to-cost ratio. The utility experiences increased costs, but these are frequently overshadowed by the potential customer savings. However, removing fast tripping may correct for only a small portion of the utility-related events that might disrupt sensitive industrial processes. This article analyzes the impacts of removing fast tripping on reliability indices and on power system economics     

Economic Evaluation of Distribution System Smart Grid Investments

This article investigates the economic benefits of smart grid automation investments. A system consisting of 7 substations and 14 feeders is used in the evaluation. Here benefits that can be quantified in terms of dollar savings are considered, termed “hard dollar” benefits. Smart grid investment evaluations to be considered include investments in improved efficiency, more cost effective use of existing system capacity with automated switches, and coordinated control of capacitor banks and voltage regulators. These smart grid evaluations are sequentially ordered, resulting in a series of incremental hard dollar benefits. Hard dollar benefits come from improved efficiency, delaying large capital equipment investments, shortened storm restoration times, and reduced customer energy use. Analyses used in the evaluation involve hourly power flow analysis over multiple years and Monte Carlo simulations of switching operations during storms using a reconfiguration for a restoration algorithm. The economic analysis uses the time-varying value of the locational marginal price. Algorithms used include reconfiguration for restoration involving either manual or automated switches and coordinated control involving two modes of control. Field validations of phase balancing and capacitor design results are presented. The evaluation shows that investments in automation can improve performance while simultaneously lowering costs.