With an increasing number of utilities rolling out smart meter initiatives, keeping electricity safe, reliable, and affordable is critical. The first step towards building a smarter grid involves implementing a technology platform that can allow two-way communication between IT applications and physical smart meters. Smart meters and various IT applications must communicate information to one another regarding outages, electric usage data, device connect status, and smart meter events. The scope of such integrations continues to grow as the footprint of smart meters and enterprise applications expands in utilities.

To enable SGG integrations, there are prebuilt integration services and adapters delivered by major software vendors in the utility space, such as Oracle. Using Oracle Utilities Smart Grid Gateway (SGG) adapters, utilities now integrate multiple advanced metering infrastructure (AMI) systems that may use different technologies, protocols, and data formats to share meter data with heterogeneous enterprise applications. Smart Grid Gateway adapters effectively decouple downstream applications from advanced metering infrastructure, enabling adoption of easy-to-adapt emerging technologies. SGG abstracts business processes from specific implementation details and acts as a data communication bridge in the overall enterprise landscape, providing flexibility and extensibility throughout the lifecycle of a smart meter implementation.

Utilities host hundreds of enterprise applications to run day-to-day business processes, such as Oracle Utilities Customer Care & Billing, Meter Data Management, Operational Device Management, Network Management System, and many more. SGG integrations support various business processes. For example:

  1. To bill the customers, utilities need electricity usage data. SGG feeds meter readings into the Meter Data Management (MDM) system and downstream billing system.
  2. If a customer moves to a new address, SGG enables utilities to connect or disconnect smart meters remotely, alleviating the need to send a crew to the customer’s premises.
  3. SGG integrations help utilities keep data in sync across their applications and head-end systems.
  4. SGG reports critical outage and restoration events from network management systems to utility applications in real time.
  5. SGG provides a foundation and implementation patterns to utilities to build custom integrations for various business processes.
  • SGG Diagram

SGG adapters handle large volumes of data from an ever-increasing list of smart devices. Utilities are now providing sophisticated user interaction to customers to track their electricity usage behavior. Now, customers can track near-real-time usage data. In the background, SGG integration services bring over interval (monthly, daily, etc.) electricity usage data from the head-end system and feed this interval data into utility applications. The head-end system provides usage data in various formats such as comma separated values (CSV) format, binary format, XML messages, etc. SGG integration services use various parsing mechanisms to parse large volumes of incoming data into individual usage readings before sending to downstream applications such as the MDM system. Utilities are also using SGG integrations to bring over weather data such as temperature, humidity, wind and precipitation to overlay with electricity usage, giving customers complete insight into their usage behavior per weather trends.

SGG adapters and integration services play a very important role in providing visibility across the electric grid. There are prebuilt SGG integrations between a utility’s network management system and enterprise applications to assist with outage detection, outage verification, and outage restoration. When Oracle Utilities Network Management System (NMS) processes trouble calls from customers, NMS issues meter ping commands to the head-end system via SGG integrations to capture meter status information. In cases of severe thunderstorms, NMS sends meter ping requests in batches to the head-end system via SGG integrations to ensure there is no power outage in a particular service territory. In cases where a power outage is detected, once the outage is restored, NMS uses Smart Grid Gateway integrations to reach the head-end system to ensure smart meters are restored by sending power restoration real-time events. The SGG platform also provides integrations and adapters for non-AMI systems to process scalar usage data to downstream billing applications for traditional manual meters.

Customer information is captured in a utility’s customer information system, which needs to be synced to downstream applications. Smart Grid Gateway integrations and adapters help utilities sync customer information across enterprise applications and systems such as Oracle Utilities Meter Data Management, Network Management System, etc. Similarly, utilities use prebuilt integrations to sync meter information and service point details and install event messages across multiple applications.

Smart Grid Gateway provides Advanced Development Kit (ADK) tools and resources to build custom integrations for utilities. Utilities may not have prebuilt integrations for all business processes or specific requirements, in which case they can leverage message patterns and foundation objects, development resources provided by SGG ADK tools to build a specific integration. Enterprise application vendors like Oracle provide both prebuilt integrations and adapter development kits to develop custom integrations.

Utility software vendors provide a wide range of integration services to meet requirements for day-to-day business processes. Smart Grid Gateway integrations help utilities reduce time, costs, and resources needed to implement business processes throughout their smart meter initiative efforts, and expedite time to market. Some of the major integrations I’ve seen and worked on most frequently include:

  • SGG integrations to load scalar and interval electricity usage data: Oracle provides prebuilt integrations such as SGG-D3-USAGE and SGG-D5-USAGE adapters to load usage data from the head-end system to the Meter Data Management application. In this case, D3 stands for Landis + Gyr and D5 stands for Itron MV90 head-end systems.
  • SGG integrations to load near-real-time AMI events: Oracle provides prebuilt integrations such as AMI Event Subscriber and SGG-D3-CIM-EVENT adapters to process advanced metering infrastructure (AMI) events in real time such as power outage/restoration, low voltage, tamper/diversion, etc.
  • SGG integrations to support Oracle Utilities Network Management System tasks: Oracle provides prebuilt integrations such as NMS-SGG adapters to process power status updates and meter pings in real time to detect and verify power outage and restoration for a particular service territory or premises.
  • SGG integration to carry out smart meter commands: Oracle provides device communication commands such as Connect Disconnect, Commission Decommission, Demand Reset, On Demand Read, and Status Check for real-time communication between enterprise applications and head-end systems (Landis + Gyr, Itron, Sensus, Elster).
  • SGG integrations to sync data across applications: Oracle delivers integrations such as ODM-MDM and CC&B-MDM prebuilt integrations to sync meter information and service points and install event attributes and customer information across applications, namely Meter Data Management (MDM), Operational Device Management (ODM), and Customer Care and Billing System (CC&B).

Smart Grid Gateway (SGG) integrations help utilities streamline smart meter initiatives in a more effective way. This includes reducing costs and complexity of data stream and business processes by introducing seamless integrations across enterprise applications, head-end systems, and smart devices. Red Clay Consulting has over fifteen years of experience implementing and building Smart Grid Gateway integrations and adapters for utilities across the globe. Learn more about our System Integration & Implementation Services.

 

About the Author:

As a Senior Consultant at Red Clay Consulting, Veeresh Hawalkhod is responsible for developing and configuring integration solutions tailored to clients’ varying needs for usage, event data upload, and device communication commands. Veeresh brings over nine years of experience in the integration space, mainly focusing on Oracle middleware products. As a subject matter expert in Oracle Fusion Middleware, he has experience designing, developing, and deploying custom integrations for enterprise distributed applications.

 

 

Utilities host a number of enterprise applications to process day-to-day tasks, including meter data management systems, customer information systems, advanced metering infrastructure, outage management systems, and more. Implementing enterprise integrations provides a strong foundation and is critical to streamline business processes, keep utilities prepared to meet changing needs, mitigate business risks, and efficiently manage utility operations. Integrations help utilities manage real-time information and transactions across enterprise applications and systems.

Every application or system used by a utility is distinct in terms of its operation and technology implementation. For example, within the Oracle Utilities Application Framework suite of enterprise applications, Operational Device Management (ODM) is the system of record for meter assets and meter testing information, Meter Data Management (MDM) stores and processes electricity usage data, Customer Care and Billing (CC&B) is used to bill the customer and process the customer requests, and Command Center is used to manage the electric grid. Each application is dependent on other applications for specific information. ODM receives the firsthand information which needs to be sent over to MDM to load electricity usage against the meter. MDM sends usage data to CC&B to bill the customer, Command Center communicates information back and forth with meters and applications. It is essential for utilities to keep all the applications and systems in sync to process day-to-day business transactions.

Let us consider some of the business processes of a utility using Oracle Utilities applications:

  1. Operational Device Management (ODM) creates field activity and sends it to Service Order Management (SOM). Eventually, information is sent to downstream applications and systems to perform field work required for meter asset testing and meter exchange.
  2. Customer Care & Billing (CC&B) receives firsthand information about customer and contacts, and this information is sent to other enterprise applications such as MDM (Meter Data Management) and NMS (Network Management System) to enable end-to-end business processes.
  3. Head-end systems such as Landis + Gyr, Sensus, Itron, and Elster collect electricity usage and events from smart/manual meters, which is sent on to enterprise applications to process and bill the customer, generating revenue for the utility.
  4. Utilities set up charging stations such as Charge Point to capture usage for charging electric vehicles, and the usage data is shared across meter management and billing systems to bill the customer.
  5. Utilities perform a rate check for validating rate calculations and comparing customer bills on different rate schedules. Utilities use enterprise applications like Customer Care and Billing to perform this task, which further requests usage information from other applications, such as the meter data management system.

There are hundreds of business processes involved in the day-to-day operations of a utility. The main challenge for utilities is to integrate heterogeneous enterprise applications and systems to seamlessly talk to each other in order to complete business processes. Service-oriented architecture (SOA) helps utilities to achieve this goal and meet their integration needs.

SOA is based on a set of industry standards which enable the flow of data between enterprise applications and legacy systems. SOA lays down a strong foundation for utilities to meet the increasing demand for integration, facilitating the interoperability, reusability, stability, and scalability to operate business processes in enterprise. SOA provides standard patterns and reference architecture to help utilities expedite their implementation efforts by making sure integrations built for enterprise take care of not only existing needs, but future needs as well.

There are many vendors in the market who provide robust tools and technology resources to implement SOA integrations for utilities. Some of the major vendors’ products are Oracle SOA Suite, IBM SOA, TIBCO SOA, and MuleSoft. These SOA suite products contain a sophisticated development environment which provides plug-n-play features to implement reusable and scalable enterprise integrations.

Let’s take an example use case to understand how SOA plays an important role in enterprise integration to build an interoperable, scalable, and reusable service portfolio for business.

Oracle Utilities Operational Device Management (ODM) receives firsthand information about meters and their manufacturer details, which are further synced over to other applications in enterprise. These meters or assets in ODM are part of a periodic asset/meter testing process where ODM determines if a meter is to be exchanged and retired if the meter set is identified as a bad lot. This business process involves sending asset testing requests or meter to be exchanged/retired requests to downstream applications to perform respective action. Enterprise integrations using Oracle SOA Suite products and tools enable seamless integration across all applications to effectively and efficiently operate such business processes at the utility.

This business process includes multiple sub tasks:

  • Create field activity in Operational Device Management. This field activity request contains periodic asset testing or meter exchange/retire requests.
  • The field activity request is sent to downstream applications such as Service Order Management, a testing system, or a mobile workforce like PCAD.
  • Once the field activity is completed, the completion details are sent to upstream applications to complete the business process.
  • In case the field activity needs to be aborted before it is processed, another task is triggered to cancel the field activity across all the applications and systems.

SOA services help utilities transform such business processes and modular tasks into specific technical deliverables. The SOA product suite provides a set of message patterns, reference architecture, and design patterns to produce robust, scalable, and reusable enterprise integrations. The design and message patterns support a publish-subscribe message model, real-time web service integrations, and batch processing references.

The below diagram provides details around a SOA suite and its components to implement the business process discussed above. A SOA suite provides a rich set of prebuilt adapters to connect to legacy and third party applications, web service integration points to process real time data, Rest API and JSON support for mobile integrations, and support for JMS queue and topic interactions.

  • Service Management Diagram

Integrations of enterprise applications are crucial to a utility’s ability to streamline their day-to-day business processes, minimize risk, and quickly adapt to changing requirements. Service-oriented architecture is the toolbox that allows utilities to reach their integration goals faster. At Red Clay Consulting, we have a proven track record of implementing enterprise integrations for utilities with a wide array of varying needs. We have implemented both productized and non-productized SOA integrations. Red Clay has worked with SOA and Smart Grid Gateway product technical architects to discuss utilities’ integration roadmaps and strategize solution recommendations. Red Clay has built integrations for large and mid-size utilities to facilitate business processes across enterprise applications, legacy systems, and third party applications. Learn more about our System Integration & Implementation Services.

 

About the Author:

As a Senior Consultant at Red Clay Consulting, Veeresh Hawalkhod is responsible for developing and configuring integration solutions tailored to clients’ varying needs for usage, event data upload, and device communication commands. Veeresh brings over nine years of experience in the integration space, mainly focusing on Oracle middleware products. As a subject matter expert in Oracle Fusion Middleware, he has experience designing, developing, and deploying custom integrations for enterprise distributed applications.

 

The electric utility industry is currently undergoing the greatest period of transformation in its history. Utilities are facing new challenges, and these challenges present opportunities for them to reevaluate business processes that have remained unchanged for decades. This blog series delves into six of the most prominent challenges, dissects them, and hypothesizes how they will shape the future of the utility industry. To better understand how the utility industry is changing, we would like to spend this introductory blog post contrasting the past and the future, while introducing each of these six challenges.

  • 1950's Ameritown

Let us introduce you to a typical utility in the 1950s. We’ll call it Ameritown Electric Company. Business is great in 1950. Each year, Ameritown makes significant strides in generating electricity more efficiently each year, and as a result, it lowers the cost of kilowatt-hours for its customers each year. Furthermore, Ameritown’s customer base, especially the residential sector, is growing so fast that it can barely keep up with demand. If we had to sum up Ameritown’s business model and the electric grid in general, the phrase would be “centralized power plants.” In 1950, the grid was made up of large power plants located many miles away from the majority of utility customers. Ameritown and other utilities of 1950 were able to amass the funds needed to build these power plants and extensive power lines because of the yearly growth in their customer base and their significant energy efficiency gains.

  • 2050 Ameritown

Fast forward 100 years, and the Ameritown Electric Company of 2050 has a completely different business model. Its customer base has stabilized, the fossil fuel industry is no longer making huge strides in innovation, and customers and regulators have become more concerned about environmental impacts. To keep up with these new challenges, Ameritown has had to innovate its business model with new technology and modernized business processes.

By 2050, the smart grid movement, or the modernization of the electric grid via information and communication technology, is reaching maturity. Utilities like Ameritown can monitor and understand the condition of their grid like never before. Decisions can be carried out in an instant through automation and remote control. Power quality and reliability are better than ever, thanks to sensors throughout the grid. The grid is more resilient due to its ability to instantly identify outages and reroute electricity. These advancements all significantly changed the way utilities operate and respond to problems, but one object had more transformational impact to the grid than any other technology: smart meters.

Just as centralized power plants were the foundation of the 1950s grid, smart meters and ancillary technologies now provide the backbone of the electric grid and all the services it provides. Their installation enables utilities to collect usage in small intervals as opposed to lump sums once a month and to communicate to and receive communications from the meters in real-time.

The most remarkable concept that smart meters helped Ameritown realize and establish is the partnership between the utility and its customers. In 1950, Ameritown customers knew almost nothing about their energy usage, except that someone would come to their property to read their meter every month, and they would get a bill mailed to them with a flat fee per kWh. Customers in 2050 now receive communication from the utility in a variety of ways. Their bills have changed. Some customers get bills emailed to them, or they view their bills online. Others are on pre-paid agreements, where they pay the same amount every month. Furthermore, the utility is no longer communicating to the customer only once per month. Some customers receive daily reports on the price of electricity. Others use apps on their smart phones to monitor their energy usage.

These tools and a variety of service agreements are necessary for customers in 2050, because they are no longer just consumers of electricity. Ameritown customers have distributed generation resources installed on their property. Residential customers might have solar panels on their roofs and electric vehicles or battery storage in their garages. Commercial or industrial customers might have invested in solar or wind farms and own private fuel cells or backup generators. Not only do these sources provide energy for their owners, the excess electricity that the owners cannot use is transferred to Ameritown’s grid and is used by other Ameritown customers. As a result, Ameritown pays its customers for their excess generation.

Now that customers in 2050 are also producers of electricity, the grid can no longer be described as a system of large, centralized power stations. The grid is decentralized, meaning it consists of many smaller generation units dispersed throughout its jurisdiction.  Even though the architecture of the grid has changed, 2050 Ameritown stills faces issues with operating near capacity. In 1950, there were periods of the day when the grid was operating at peak capacity, mostly when the entire family came home from work and school and started to turn on appliances. Ameritown’s solution was to build more power plants. 2050 Ameritown still has periods of the day with peak usage, but the solution has changed. Instead of building more generation sites when only incremental increases are needed, Ameritown has a supplemental solution called demand response. Its customers willingly sign up to be alerted during periods of heavy load, and when they receive those alerts, they will reduce their usage. In return, the utility reimburses them for their flexibility.

Demand response is not the only customer-centric program offered by Ameritown Electric Company in 2050. It has electric vehicle charging stations installed around the city of Ameritown, which allows customers to charge their vehicles while running errands. The customers then pay for the electricity on their monthly service bill. Ameritown also provides lease agreements to customers who cannot afford or choose not to own solar panels. For a small monthly fee, customers get utility-owned solar panels installed on their roofs, and they do not have to worry about maintenance and operation of the solar systems. This sampling of programs is diverse and complex. When implementing these programs, Ameritown did not have the in-house expertise needed to install these systems, nor do they have the resources to operate all these components on a daily basis. Therefore, Ameritown partnered with third-party vendors to make these programs a reality. One vendor owns and maintains the electric vehicle charging stations, another installs solar panels for the utility, and a third operates a control center focused on forecasting periods of high use and alerting demand response customers to reduce their usage.

To interface with myriad vendors and software applications that Ameritown now requires in an efficient and cost-effective way, it utilizes communication standards such as MultiSpeak and Common Information Model (CIM). These standards are necessary since the number of software applications, and therefore, the number of interfaces has increased manyfold in the last 100 years. From a governance and cost perspective, it is simply unfeasible to have multiple interfaces, each with its own format. Hence, Ameritown worked with several other utilities a few decades ago to determine standards with which several software applications are compliant. This helps in building robust and product-independent integrations, as opposed to point-to-point integrations that change from vendor to vendor.

With high amounts of automation, inter-communication, and digitization, Ameritown now must account for a unique set of challenges that it did not have some 100 years ago. These challenges are related to that of information security and protecting customers from data theft, fraud, and potential terror attacks. Ameritown has had to invest in ensuring all its software systems can pass security audits and meet information security standards set by local councils and organizations such as NERC. Furthermore, Ameritown has trained its staff to reduce data breaches and notice security vulnerabilities and breaches.

As a whole, 2050 Ameritown Electric Company is a much more diverse utility than 1950 Ameritown. In 1950, its business model focused on reliably and safely delivering electricity from large power plants across many miles of transmission and distribution lines to its customers. In 2050, Ameritown is still focused on delivering electricity safely and reliably, but it is receiving electricity from many different sources, and its customers have become active contributors. Ameritown provides them with a multitude of information about their energy usage and customizable service agreements to fit their needs. Customers are now willing to actively control their energy usage for incentives. This expansion of service offerings is made possible through Ameritown’s partnerships with vendors, and it is able to safely and reliably provide these services through its investment in communication standards and security.

  • Transformed, Innovative 2050 Ameritown

So how does a utility like Ameritown successfully adapt to thrive in an increasingly digital world, with very different customer and regulatory requirements than those that existed for the first hundred years of the grid’s existence? Please follow our blog over the next six weeks as we explore how the most prominent challenges electric utilities face today present opportunities to improve business processes and operations.

For more information on how Red Clay can help your utility optimize operations, please visit Services or contact sales@redclay.com

 

Click here to read the next blog post in this series.

 

About the Authors

As a senior consultant for Red Clay ConsultingAnkit Malik works primarily in analysis of software functionality and client requirements, designing a complete solution, leading teams performing the configuration or custom development required to meet requirements, leading testing efforts including unit, string and migration testing, and delivery support. Ankit offers a strong background of C and C++ programming, as well as significant experience in XML, XPath and many other scripting languages. Ankit has worked with SOAP, AJAX, and is knowledgeable of web services. He is also experienced in Middleware architecture and technologies, including BPEL and Oracle SOA Suite, and has worked extensively with two-way device communications. 

As a consultant at Red Clay Consulting, Megan Milam has comprehensive training and functional experience with Oracle Utilities Application Framework software and Oracle Utilities Lodestar software Furthermore, her Bachelor of Science degree in electrical engineering, with an emphasis in power systems and smart grid technology, and her previous work experience at a transmission System Operator give her a technical background with a firm understanding of industry best practices and an ability to implement optimal solutions

 

Click here to read this blog series from the beginning.

The electric utility industry is currently undergoing the greatest period of transformation in its history. Utilities are facing new challenges, and these challenges present opportunities for them to reevaluate business processes that have remained unchanged for decades. This blog series delves into six of what we consider to be the most impactful challenges, dissects them, and hypothesizes how they will shape the future of the utility industry. This blog post explores the first challenge we have identified – the process of adapting to new customer preferences that demand more information and more channels of communication from utilities than ever before.

  • Customer Presentment

Justice Louis D. Brandeis once wrote, “Sunlight is said to be the best of disinfectants; electric light the most efficient policeman.” True to his statement, the utility industry is moving towards a more transparent environment, with greater customer engagement and higher levels of energy usage data available to customers. This information can then be used by the customer to take advantage of different rates and discounts from a utility, or simply to use energy more efficiently.

The utility landscape has altered significantly in the last decade. The industry has undergone massive levels of digitization, and smart meters capable of reporting usage, issuing alerts for outages, etc. are being installed in the field for large, industrial customers and residential customers alike. Technological advances in the fields of networking and information technology are making the internet of things possible on a large scale. These changes have led to a disruption in the utility business model, making utilities evolve into more than just commodity energy suppliers.

1.1     Why does customer presentment matter?

A key difference in the way utilities must now operate is an increased focus on customer experience. Customer satisfaction levels are important not just as potential entry into new markets for ‘beyond the meter’ services, but for regulatory negotiations as well. Customer satisfaction levels often receive more attention in the aftermath of a massive disruption in service, or prolonged or sudden drops in the customer satisfaction levels. For example, let’s say our “Ameritown” utility experienced a decline in customer satisfaction levels consistently over a two-year period. The state public commission requires an audit of the utility’s customer-service practices. Aggressive cost-cutting, a failed implementation of a new online customer portal, and a general lack of commitment to customer service were the main contributors to this decline. In response, Ameritown made an investment to improve customer service, particularly using the digital channels. This increased the expenses the utility devoted to customer satisfaction and ultimately eroded the cost savings the utility had achieved.  Had the utility been more proactive with their customer satisfaction ratings from the beginning, costly overruns could have been avoided.

Increased commitment to customer satisfaction will be crucial in two ways. First, it will be useful for reducing barriers to entry into new services that the current energy landscape will provide, such as beyond-the-meter services, dynamic pricing, and collaborations with third party vendors like cable and telecom companies. Second, high levels of consumer trust and confidence can raise barriers for new market entrants and prevent customers from switching to a new, untried market entrant.

Improving customer experience also benefits utilities by providing customers with a feedback loop of their usage patterns and potential costs, both monetary and environmental. This is because as customers get feedback on their energy usage, they can mold their energy use patterns, identify energy inefficient devices, and sign up for new utility programs that reward shifting usage to non-peak hours. This will reduce the need for new generation facilities, make the existing resources last longer, and ultimately be better for the environment as well.

For these endeavors to be successful, it is imperative that the customer engagement solutions from the utility are used by the end user. The bar for successful implementations of customer engagement solutions is constantly set higher and higher. Companies like Google and Netflix, while not direct competitors in the utility space, set the ambitious standards in user interface design that utilities must now aim to meet. Customers expect the customer engagement system to be intuitive, fast, predictive, and helpful.

1.2     What does good customer presentment look like?

  • Good customer engagement should be fast, intuitive, helpful, and predictive.

An intuitive customer interface for a digital self-service portal is crucial. If an online portal requires the deductive reasoning skills of Sherlock Holmes to navigate through a maze of clicks and menus just to report an outage, that’s probably not a good design! Similarly, a cluttered IVR system without an option to reach a customer service representative is not intuitive enough for customers to use. A familiar, easy-to-use interface for both reporting and gathering information is key to a successful implementation of a customer engagement platform, using both mobile and web-based apps alongside IVR-based solutions.

Loading speed, especially for web-based apps, is also vital to a successful implementation of a customer engagement solution. A feature-rich interface devoid of loading speed will be useless to the customers. Breaking features into multiple screens, or even forgoing some features, may be necessary to ensure the customer experience is not affected by lack of speed.

While showing the usage patterns of the past and present is constructive, users also want to see predictive analysis to determine what their usage and bills would look like in the future. This would also help them determine if enrolling in some of the customer programs the utility offers would be of use to them. The ability to predict future usage is essential for customers to determine how they can mold their usage patterns. Predictive analysis is effective both in terms of monetary savings – for the customer and utility – and environmental impact, as shifting usage to non-peak times often results in lowered generation requirements, which reduces environmental impact.

Perhaps the most important facet of customer engagement is helpfulness. Utilities must consistently strive to make the customer experience as painless as possible by consistently listening to feedback and efficiently training customer service representatives. A customer-focused approach, both during the designing of engagement solutions and the training of customer reps, goes a long way in ensuring that customers successfully utilize the platforms and tools available to get what they need.

In this blog post, we saw how information technology and the smart grid provide a unique opportunity for utilities to engage customers in new ways and transform their business model from energy providers to service providers capable of offering multiple beyond-the-meter services. In the next blog post, we’ll discuss how a more decentralized grid makes this transition into service providers increasingly necessary.

 

Visit Implementation and Integration Services or contact sales@redclay.com to learn more about our experience building effective digital self-service portals for our clients.

 

 Click here to read the next blog post in this series.

 

About the Author

As a senior consultant for Red Clay ConsultingAnkit Malik works primarily in analysis of software functionality and client requirements, designing a complete solution, leading teams performing the configuration or custom development required to meet requirements, leading testing efforts including unit, string and migration testing, and delivery support. Ankit offers a strong background of C and C++ programming, as well as significant experience in XML, XPath and many other scripting languages. Ankit has worked with SOAP, AJAX, and is knowledgeable of web services. He is also experienced in Middleware architecture and technologies, including BPEL and Oracle SOA Suite, and has worked extensively with two-way device communications. 

 

Click here to read this blog series from the beginning.

The electric utility industry is currently undergoing the greatest period of transformation in its history. Utilities are facing new challenges, and these challenges present opportunities for them to reevaluate business processes that have remained unchanged for decades. This blog series delves into six of what we consider to be the most impactful challenges, dissects them, and hypothesizes how they will shape the future of the utility industry. This blog post focuses on the most popular customer behavior program for energy management: demand response.

  • Evolution of the Smart Grid: Customer Behavior Programs, Demand Response

This past summer, specifically during the month of June 2017, temperatures blasted the Southwest with a heatwave that led most people to crank up their air conditioning. During this time, utilities across five states, from California to Texas, broke their all-time records for peak demand. ERCOT, the Electric Reliability Council of Texas, broke its previous record three times in one afternoon on July 20th. The demand was met without issues, but ERCOT assesses its current summer reserve of 18.9% will decrease to less than 10% within a decade, a small margin if their customers’ demand is underestimated.

One method of increasing generation capacity is by building new power plants. For many decades, a utility’s business model focused on building infrastructure. The annual increase in electricity consumption was always large enough to support new investments in power generation. In this scenario, ERCOT’s utilities would likely build a natural gas plant, after considering the Clean Air Act requirements and the cost of the various types of fuels. If building new plants was the only option available to utilities, Maximilian Auffhammer, an environmental economist at the University of California, calculated it would cost U.S. utilities a total of $180 billion during the 21st century to meet rising demand peaks. This magnitude of investment is unattainable for many utilities. In today’s market, the electricity load is growing gradually, and utilities must find alternatives to combat the cost of building new power plants or utilizing expensive auxiliary generators when demand reaches peak levels.

Solutions that are financially feasible focus on energy efficiency and optimization. Energy management includes any programs or technology that enable customers to manage their electricity use to benefit themselves and the utility. One well-known method is demand response, a program in which consumers reduce consumption based on market signals. Instead of requiring a utility to manipulate supply to match demand, demand response empowers the customer to manipulate demand to match supply. Depending on the program, consumers can respond to fluctuations in price, demand charges, or critical thresholds on the electric grid. During times of peak load, high wholesale energy prices, or compromised supply situations, the utility sends signals to customers enrolled in these programs asking them to reduce their load. The utility benefits from additional control of a flexible load, and the customer enrolled in demand response benefits from monetary compensation for their flexibility.

Two markets, retail and wholesale, exist for demand response programs. The latter, often called supply-side programs, are usually offered by independent system operators (ISO) or regional transmission organizations (RTO) and allow demand response providers to bid into the wholesale electricity market alongside traditional generation plants. According to surveys from the Federal Energy Regulatory Commission (FERC), two of the top demand response programs are wholesale market programs. Emergency Response and Load as Capacity Resources account for 24% and 15% of total peak load reduction respectively. One of the leaders in capacity resource demand response, the Pennsylvania, Jersey, Maryland Power Pool (PJM) RTO, signed contracts for almost 170,000 MW of capacity in 2016, and roughly 12,500 MW of the total were demand response resources, equaling 7 percent of the peak demand. Since demand response is reducing energy during peak times when electricity costs are higher, PJM estimates its customers saved as much as $650 million in a summer month. PJM is building increased integration of demand response into its supply forecast and expects to achieve the increase without any adverse effects on service.

Demand response is not a new concept. According to a survey conducted by Utility Dive, 66 percent of utility executives said their utilities offer energy management and efficiency services to customers. According to FERC’s assessment of demand response in 2017, over 9 million customers are enrolled in incentive-based programs, a number that has remained steady in recent years. Wholesale incentive-based programs include emergency demand response and bidding as capacity reserves. On the other hand, time-based programs increased by 10% to include over 7.5 million customers. Dependent on rate structures, these programs are offered by utilities as retail market demand response. The most common rate structures are real-time pricing (hourly pricing based on the market), critical peak pricing (increased prices during peak hours), and time-of-use rates (predefined pricing for periods throughout the day). Utilities can only offer time-based rates to customers with capable meters, so a 10% increase could be correlated in part to the increase in the number of smart meters installed, approaching 43% of total meters in 2015, according to FERC.

With the addition of many smart grid initiatives across the U.S., specifically advanced metering infrastructure (AMI) meter installations, more and more customers are becoming eligible for retail programs. Specifically, residential and small commercial customers account for the largest percentage and are targeted for direct load control programs, which give utilities or third-party demand response aggregators direct access to controllable appliances. This type of control requires communication networks to send messages to the appliance controllers when certain conditions are met. These networks and other modernization efforts give demand response the opportunity to work in conjunction with variable renewable energy. In the future, air conditioners, water heaters, and electric vehicle charging stations could be cycled quickly to respond to spikes or dips from wind and solar. A study by Peak Load Management Alliance (PLMA) determined that industry professionals rate demand response as the second-best way to handle variable energy sources (38%), second only to energy storage (43%).

In addition to the opportunity for retail demand response to integrate with renewable energy, industry leaders predict supply-side demand response can provide other services to distribution grid operations. Some of the services focus on the quality of the electricity delivered, such as steady-state voltage management, phase balancing, and power quality. These goals are dependent on grid modernization technology such as sensors and automatic grid controls, as well as close communication with power generation sources.

The existence of two different markets for demand response opens the possibility of incompatible programs offered by a utility and the utility’s ISO or RTO, but many states and their Public Utility Commissions (PUC) are organizing workshops or working groups to ensure the retail and wholesale programs are complementary. Instead of the $180 billion investment in new plants mentioned at the beginning of this article, supply-side demand response providers can potentially prevent the need for new generating units, as well as improve electricity power quality. Paired with behind-the-meter demand response programs that use time-of-use (TOU) rates to flatten the load curve and that increase the adoption of renewable energy by compensating for its variability, demand response is poised to be a powerful tool in energy efficiency for the smart grid.

When utilities consider redesigning their business models or implementing new technologies and programs, they often cite regulatory obligations as one of the leading obstacles they face. In contrast, regulatory requirements have not been a concern for many demand response implementations. In January 2016, the U.S. Supreme Court upheld FERC Order 745, which ensures demand response providers in the wholesale market will be compensated for their load reduction at the same rate electricity generators are compensated. On the retail side, the California PUC mandated its utilities must enroll their residential customers in TOU rates by 2019, a trend being picked up by other utilities.

The biggest obstacle to demand response is not regulation, but customer response. Utilities must devote resources to informing their customers about how demand response works and how programs could benefit them. Before switching large numbers of customers to time-based rates, pilot programs must gauge how customers react to the new rates and if opt-out opportunities are needed. For incentive-based programs like load control, customers can be hesitant to sign up without assurances from the utilities that their air conditioners, water heaters, electric cars, etc. will be cycled in a way that provides the least disruption to their lifestyle and that they will be compensated fairly for the trade-off.

Overall, demand response builds upon the new partnership-style relationships utilities have with their customers, thanks to customer presentment programs. Furthermore, demand response programs will become increasingly effective as they continue to utilize advancing smart grid capabilities, including communication networks which we will discuss in a future post in this series. But before we dive into how communication technology is changing our electric grid, the next blog post discusses the impact of third-party vendors in the energy industry, including influential demand response providers.

 

For more information on how Red Clay can provide technical solutions for your demand response programs, visit Services or contact sales@redclay.com

 

Click here to read the next blog post in this series.

 

About the Author

As a consultant at Red Clay Consulting, Megan Milam has comprehensive training and functional experience with Oracle Utilities Application Framework software and Oracle Utilities Lodestar software Furthermore, her Bachelor of Science degree in electrical engineering, with an emphasis in power systems and smart grid technology, and her previous work experience at a transmission System Operator give her a technical background with a firm understanding of industry best practices and an ability to implement optimal solutions.

 

Sources

https://texasenergyreport.com/blog/2017/12/18/ercot-power-reserve-margin-cut-in-half-report/
http://www.pnas.org/content/114/8/1886
https://www2.illinois.gov/sites/ipa/Documents/CUB-Comments-Appendix-C-Brattle-Group-Report-Quantifying-Demand-Response-Benefits-PJM.pdf
https://www.greentechmedia.com/articles/read/utilities-see-distributed-generation-as-a-challenge-and-owning-it-as-the-so#gs.25N9US0
https://www.ferc.gov/legal/staff-reports/2017/DR-AM-Report2017.pdf
https://www.peakload.org/
https://www.utilitydive.com/news/updated-supreme-court-upholds-ferc-order-745-affirming-federal-role-in-de/412668/
http://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_Website/Content/Meetings_and_Events/Chico.pdf

 

Click here to read this blog series from the beginning.

The electric utility industry is currently undergoing the greatest period of transformation in its history. Utilities are facing new challenges, and these challenges present opportunities for them to reevaluate business processes that have remained unchanged for decades. This blog series delves into six of what we consider to be the most impactful challenges, dissects them, and hypothesizes how they will shape the future of the utility industry. This blog post explores the second challenge we have identified – the transition from centralized electric generation towards decentralized grids with distributed energy resources.

  • Ameritown Utility and the Decentralized Grid

On October 29th, 2012, Hurricane Sandy tore through New Jersey and New York. Communities were flooded, and more than 2.6 million people lost power. The storm was unavoidable, but some communities weathered the aftermath better than others. In the Newark Bay town of Bayonne, Midtown Community School became a literal light in the midst of darkness. Thanks to the foresight of local officials eight years prior, the school had a hybrid backup solar system installed on its roof that was large enough to power the building independent of the grid. During the aftermath of Sandy, the solar panels ran in tandem with a diesel generator, and the school opened its doors to over 50 evacuees.

This story is not an isolated event. A quick Google search returns dozens of similar stories about renewable energy powering homes and communities during emergency recovery situations. The contrast between having power and being in the dark during an emergency drastically highlights how diversification of energy sources is extremely beneficial. However, renewables have a time and place outside of worst-case scenarios. Increasingly, day-to-day life in the United States depends on renewable energy to provide safe, reliable, and quality electricity.

2.1 The Current State of Renewables

In 2016, 15% of U.S. electricity generation was supplied by renewable energy sources, excluding nuclear power. That translates to over 600 billion kWh of electricity per year. Let’s break this percentage down into renewable energy types to better understand how renewable generation might expand in the future. Hydroelectricity makes up 6.5% of U.S. electricity generation. This percentage is unlikely to change significantly, because hydroelectric dams can only be built on bodies of water with certain geological features, and the U.S. does not have many remaining locations that meet these requirements. Plus, hydro plants can be disruptive to their surrounding ecosystems, so ecological concerns must always be taken into account when considering new dams. Biomass, or the conversion of organic materials into fuel, contributes 1.5% of the total electricity generated. The three main types of biomass generation are biofuels (mainly ethanol), wood and foliage products, and fuels produced from landfill and sewage waste. New biomass innovations are constantly being researched, but biomass is limited to how much organic matter can be sustainably grown and/or harvested. Furthermore, biomass still involves burning fuel, so it is not a carbon-zero energy source. Only 0.4% of total electricity in the U.S. is generated by geothermal plants currently, but the technology has potential. Utility-scale geothermal generation harnesses the Earth’s heat by pumping heated water or steam from its crust to power generators that, in turn, produce electricity. Geothermal energy can be accessed across many parts of the country, and it is a zero-carbon energy source. However, more research is needed to determine the geological impacts of building these plants, and there are financial obstacles as well. A new geothermal plant requires significant capital investment upfront, and the cost to generate a kWh of electricity can be as much as 16 times more expensive than a kWh from a traditional coal plant. The final two renewable sources are wind and solar. At 5.6%, wind is the second most common type of renewable generation. 41 out of the 50 states have utility-scale wind installations, and almost 11% of Texas’ generation comes from wind energy. Currently, solar only contributes 0.9% of the national total, but it is the fastest growing form of renewable electricity generation. All 50 states have solar capacity installed, with California being the prominent leader. Almost 10% of its generation comes from solar.

The first three sources, hydro, biomass, and geothermal, all share a common trait: they are dispatchable energy resources. Dispatchable generation is generation that utilities can control and schedule. Hydroelectric dams can release water on command, biomass facilities can ration fuel, and geothermal plants can supply water or steam to their generators as needed. Each of these sources has a reliable and constant source of energy, which contrasts with wind and solar generation sources. Wind and solar are both known as variable renewable energy (VRE), meaning their generation fluctuates due to uncontrollable external factors – in this case, changing weather patterns. Utilities cannot control wind and solar generation in the same way other sources can be controlled. One minute, solar panels could be operating at full capacity; the next minute, a cloud could cover the sun, and the panels are reduced to generating at 40%. The same is true for wind generation. A storm pattern could move into the area and significantly change the output from local wind turbines.
We have been focusing on utility-sized variable renewable energy generation, but each of these sources also has privately-owned, small-scale applications. Distributed energy resources (DER) are localized energy generators that produce power for the home or building to which they are attached. Solar panels are the most common form of DERs – small-scale residential and small business solar photovoltaic systems produced an additional 19 billion kWh in 2016 – which means the most common type of distributed energy generation is variable renewable energy. Since the majority of DERs are not controlled or maintained by the utility, the utility relies mainly on forecasting models to predict what generation they can expect, although utilities can receive communications from meters and sensors in the grid.

2.2 Preparing for a Future Filled with Distributed Energy Resources

In our introductory blog post, we hypothesized about what a typical American utility – “Ameritown” – would look like in 2050. Part of the picture we painted depicted utility customers becoming electricity producers via distributed energy resources and being compensated by the utility for the excess electricity they generate. However, we left a lot of uncertainties unanswered. How much variable renewable energy can the grid support? How will utilities cover their operational costs when customers only rely on them for part of their demand? California and New York have pledged to produce 50% of their power from renewable sources by 2030, Vermont pledged 75% by 2032, and Hawaii pledged 100% by 2045. In fact, only 13 states do not have renewable portfolio plans or targets, so the utility of the future needs to address these questions today.

  • How much variable renewable energy can the grid support?

The first question points to the technical limit of variable renewable energy (VRE) penetration. First of all, advanced metering infrastructure (AMI) and other sensors throughout the distribution and transmission network will allow operators to better monitor and identify disturbances or instabilities. To benefit from the increased monitoring capabilities, the infrastructure of the electric grid needs to be updated with control automation that can immediately respond. These improvements will allow the transmission and distribution networks to maintain stability and reliably deliver electricity from VRE sources, but despite these improvements, VREs are constrained by their capacity factors. Capacity factor is described as the percentage of time a generation plant is running relative to how much capacity is installed. Traditional generation sources usually have capacity factors of around 90 percent, because they can run continuously except for maintenance and repair downtime. VREs are on the opposite end of the spectrum. They can only generate electricity when the sun is shining or the wind is blowing. Based on estimations we have from installed wind turbines and solar photovoltaic systems, the solar capacity factor is 20%, and the wind capacity factor is 34%. Furthermore, most researchers agree that the capacity factor of a source is equal to its maximum penetration into the electric grid. From these numbers, the grid can be expected to handle a maximum of 54% variable renewable energy, and the remaining 46% must come from other sources. Innovation can always surprise us, but for grid planning purposes, the variability of wind and solar must be combatted by integrating quick and cheaply dispatchable sources to cover the remaining 46%.

  • How will utilities cover their operational costs when customers only rely on them for part of their demand?

The second question hints at the economic considerations. As more customers become distributed energy resource owners, the electricity they demand from the utility decreases, and the compensation they expect for generating electricity increases. Utilities will have to revise their business models to continue to cover their operational costs as their customer base shrinks. Furthermore, utility-scale solar and wind generation has a phenomenon known as “merit order” with which to contend. Utilities dispatch electricity from the cheapest source first, and wind and solar generators produce electricity without costly fuel, making them virtually “free.” Furthermore, VRE responds to weather conditions, so its generation floods the market at the same time, which lowers the wholesale price. During sunny days or windy nights, they produce electricity. Solar and wind VRE cannot schedule their generation. As VRE penetration increases, it will become less and less profitable. Renewable energy is sustainable, cleaner and – once systems are installed – cheaper to produce than fuel-based generation methods. It also enables fuel independency. Customers benefit by supplementing their own generation to lower their monthly bills, and environmental regulations are met by the decrease in pollution and other waste. However, utilities must address the technical and economic limitations of variable and distributed renewable energy sources. We will spend the next blog post discussing some of the customer programs and technologies utilities can use to complement increased renewable energy penetration.

 

To learn more about Red Clay’s work implementing solutions for net energy metering programs, read Grid Energy Storage: A Look Into the Future of Grid Resources, or contact sales@redclay.com

 

Click here to read the next blog post in this series. 

 

About the Author

As a consultant at Red Clay Consulting, Megan Milam has comprehensive training and functional experience with Oracle Utilities Application Framework software and Oracle Utilities Lodestar software Furthermore, her Bachelor of Science degree in electrical engineering, with an emphasis in power systems and smart grid technology, and her previous work experience at a transmission System Operator give her a technical background with a firm understanding of industry best practices and an ability to implement optimal solutions

 

Sources
www.eia.gov