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 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.

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.

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.

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.

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 Consulting, Ankit 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 focuses on the most popular customer behavior program for energy management: 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
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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