Tag: AMI/AMR

At Your Service

Today’s utility companies are being driven to upgrade their aging transmission and distribution networks in the face of escalating energy generation costs, serious environmental challenges and rising demand for cleaner, distributed generation from both developing and digital economies worldwide.

The current utilities environment requires companies to drive down costs while increasing their ability to monitor and control utility assets. Yet, due to aging infrastructure, many utilities operate without the benefit of real-time usage and distribution loads – while also contending with limited resources for repair and improvement. Even consumers, with climate change on their minds, are demanding that utilities find more innovative ways to help them reduce energy consumption and costs.

One of the key challenges facing the industry is how to take advantage of new technologies to better manage customer service delivery today and into the future. While introducing this new technology, utilities must keep data and networks secure to be in compliance with critical infrastructure protection regulations. The concept of “service management” for the smart grid provides an approach for getting started.

A Smart Grid

A smart grid is created with new solutions that enable new business models. It brings together processes, technology and business partners, empowering utilities with an IP-enabled, continuous sensing network that overlays and connects a utility’s equipment, devices, systems, customers, partners and employees. A smart grid also enables on-demand access to data and information, which is used to better manage, automate and optimize operations and processes throughout the utility.

A utility relies on numerous systems, which reside both within and outside their physical boundaries. Common internal systems include: energy trading systems (ETS), customer information systems (CIS), supervisory control and data acquisition systems (SCADA), outage management systems (OMS), enterprise asset management (EAM); mobile workforce management systems (MWFM), geospatial information systems (GIS) and enterprise resource planning systems (ERP).

These systems are purchased from multiple vendors and often use a variety of protocols to communicate. In addition, utilities must interface with external systems – and often integrate all of them using a point-to-point model and establish connectivity on an as-needed basis. The point-to-point approach can result in numerous complex connections that need to be maintained.

Service Management

The key concept behind service management is the idea of managing assets, networks and systems to provide a “service,” as opposed to simply operating the assets. For example, Rolls Royce Civil Aerospace division uses this concept to sell “pounds of thrust” as a service. Critical to a utility’s operation is the ability to manage all facets of the services being delivered. Also critical to the operation of the smart grid are new solutions in advanced meter management (AMM), network automation and analytics, and EAM, including meter asset management.

A service management platform provides a way for utility companies to manage the services they deliver with their enterprise and information technology assets. It provides a foundation for managing the assets, their configuration, and the interrelationships key to delivering services. It also provides a means of defining workflow for the instantiation and management of the services being delivered. Underlying this platform is a range of tools that can assist in management of the services.

Gathering and analyzing data from advanced meters, network components, distribution devices, and legacy SCADA systems provides a solid foundation for automating service management. When combined with the information available in their asset management systems, utility companies can streamline operations and make more efficient use of valuable resources.

Advanced Reading

AMM centers on a more global view of the informational infrastructure, examining how automatic meter reading (AMR) and advanced metering infrastructure (AMI) integrate with other information systems to provide value-added benefits. It is important to note that for many utilities, AMM is considered to be a “green” initiative since it has the ability to influence customer usage patterns and, therefore, lower peak demand.

The potential for true business transformation exists through AMM, and adopting this solution is the first stage in a utility’s transformation to a more information-powered business model. New smart meters are network addressable, and along with AMM, are core components of the grid. Smart meters and AMM provide the capability to automatically collect usage data in near real time and to transport meter reads at regular intervals or on demand.

AMR/AMIs that aggregate their data in collection servers or concentrators, and expose it through an interface, can be augmented with event management products to monitor the meter’s health and operational status. Many organizations already deploy these solutions for event management within a network’s operations center environments, and for consolidated operations management as a top-level “manager of managers.”

A smart grid includes many devices other than meters, so event management can also be used to monitor the health of the rest of the network and IT equipment in the utility infrastructure. Integrating meter data with operations events gives network operations center operators a much broader view of a utility’s distribution system.

These solutions enable end-to-end data integration, from the meter collection server in a substation to the back-end helpdesk and billing applications. This approach can lead to improved speed and accuracy of data, while leveraging existing equipment and applications.

Network Automation and Analytics

Most utility companies use SCADA systems to collect data from sensors on the energy grid and send events to applications with SCADA interfaces. These systems collect data from substations, power plants and other control centers. They then process the data and allow for control actions to be sent back out. Energy management and distribution management systems typically provide additional features on top of SCADA, targeting either the transmission or distribution grids.

SCADA systems are often distributed on several servers (anywhere from two to 100) connected via a redundant local area network. The SCADA system, in turn, communicates with remote terminal units (RTUs), other devices, and other computer networks. RTUs reside in a substation or power plant, and are hardwired to other devices to bring back meaningful information such as current megawatts, amps, volts, pressure, open/closed or tripped. Distribution business units within a utility company also utilize SCADA systems to track low voltage applications, such as meters and pole drops, compared to the transmission business units’ larger assets, including towers, circuits and switchgear.

To facilitate network automation, IT solutions can help utilities to monitor and analyze data from SCADA systems in real time, monitor the computer network systems used to deploy SCADA systems, and better secure the SCADA network and applications using authentication software. An important element of service management is the use of automation to perform a wide range of actions to improve workfl ow efficiency. Another key ingredient is the use of service level agreements (SLAs) to give a business context for IT, enabling greater accountability to business user needs, and improving a utility’s ability to prioritize and optimize.

A smart grid includes a large number of devices and meters – millions in a large utility – and these are critical to a utility’s operations. A combination of IT solutions can be deployed to manage events from SCADA devices, as well as the IT equipment they rely on.

EAM For Utilities

Historically, many utility companies have managed their assets in silos. However, the emergence of the smart grid and smart meters, challenges of an aging workforce, an ever-demanding regulatory environment, and the availability of common IT architecture standards, are making it critical to standardize on one asset management platform as new requirements to integrate physical assets and IT assets arise (see Figure 1).

Today, utility companies are using EAM to manage work in gas and electric distribution operations, including construction, inspections, leak management, vehicles and facilities. In transmission and substation, EAM software is used for preventative and corrective maintenance and inspections.

EAM also helps track financial assets such as purchasing, depreciation, asset valuation and replacement costs. This solution helps integrate this data with ERP systems, and stores the history of asset testing and maintenance management. It integrates with GIS or other mapping tools to create geographic and spatial views of all distribution and smart grid assets.

Meter asset management is another area of increasing interest, as meters have an asset lifecycle similar to most other assets in a utility. Meter asset management involves tracking the meter from receipt to storeroom, to truck, to final location – as compared to managing the data the meter produces.

Now there is an IT asset management solution with the ability to manage meters as part of the IT network. This solution can be used to provision the meter, track configurations and provide service desk functionality. IT asset management solutions also have the ability to update meter firmware, and easily move and track the location and status of the assets over time in conjunction with a configuration database.

Reducing the number of truck rolls is another key focus area for utility companies. Using a combination of solutions, companies can:

  • Better manage the lifecycles of physical assets such as meters, meter cell relays, and broadband over powerline (BPL) devices to improve preventive maintenance;
  • Reconcile deployed asset information with information collected by meter data management systems;
  • Correlate the knowledge of physical assets with problems experienced with the IT infrastructure to better analyze a problem for root cause; and
  • Establish more efficient business process workflows and strengthen governance across a company.

Utilities are facing many challenges today and taking advantage of new technologies that will help better manage the delivery of service to customers tomorrow. The deployment of the smart grid and related solutions is a significant initiative that will be driving utilities for the next 10 years or more.

The concept of “service management” for the smart grid provides an approach for getting started. But these do not need to be tackled all at once. Utilities should develop a roadmap for the smart grid; each one will depend on specific priorities. But utilities don’t have to go it alone. The smart grid maturity model (SGMM) can enable a utility to develop a roadmap of activities, investments and best practices to ensure success and progress with available resources.

Empowering the Smart Grid

Trilliant is the leader in delivering intelligent networks that power the smart grid. Trilliant provides hardware, software and service solutions that deliver on the promise of Advanced Metering and Smart Grid to utilities and their customers, including improved energy efficiency, grid reliability, lower operating cost, and integration of renewable energy resources.

Since its founding in 1985, the company has been a leading innovator in the delivery and implementation of advanced metering infrastructure (AMI), demand response and grid management solutions, in addition to installation, program management and meter revenue cycle services. Trilliant is focused on enabling choice for utility companies, ranging from meter, network and IT infrastructures to full or hybrid outsource models.

Solutions

Trilliant provides fully automated, two-way wireless network solutions and software for smart grid applications. The company’s smart grid communications solutions enable utilities to create a more efficient and robust operational infrastructure to:

  • Read meters on demand with five minute or less intervals;
  • Improve cash flow;
  • Improve customer service;
  • Decrease issue resolution time;
  • Verify outages and restoration in real time;
  • Monitor substation equipment;
  • Perform on/off cycle reads;
  • Conduct remote connect/disconnect;
  • Significantly reduce/eliminate energy theft through tamper detection; and
  • Realize accounting/billing improvements.

Trilliant solutions also enable the introduction of services and programs such as:

  • Dynamic demand response; and
  • Time-of-use (TOU), critical peak pricing (CPP) and other special tariffs and related metering.

Solid Customer Base

Trilliant has secured contracts for more than three million meters to be supported by its network solutions and services, encompassing both C&I and residential applications. The company has delivered products and services to more than 200 utility customers, including Duke Energy, E.ON US (Louisville Gas & Electric), Hydro One, Hydro Quebec, Jamaica Public Service Company Ltd., Milton Hydro, Northeast Utilities, PowerStream, Public Service Gas & Electric, San Diego Gas & Electric, Toronto Hydro Electric System Ltd., and Union Gas, among others.

Customer Relationships and the Economy

A little over a year ago, the challenges facing the global energy and utilities market were driving a significant wedge between utilities and their customers. In Western European markets, price increases across gas, electricity and water, combined with increased corporate earnings, left many utilities in the uncomfortable position of being seen as profiteering from customers unable to change suppliers for significant benefit.

Headline-makers had a field day, with gross simplification of the many utilities’ business models. They made claims about “obscene profits,” while citing the “long-suffering” consumer position [1]. Now, more than a year later, gas and electricity prices are falling, but the severity and pace of the wider economic downturn has given no time for utilities to re-position themselves with customers. Brand and relationship-enhancing programs such as smart metering and energy efficiency are still largely in their infancy.

The evolving relationship with the customer base, where customer expectations are resulting in a more participatory, multi-channel engagement, comes at a time when the evolution of smart networks and metering solutions are on the cusp of driving down cost to serve and improving service levels and options. Significant benefits accrue from consumption measurement and management capabilities. Benefits also result from the opportunity to transform the consumer relationship by pushing into new areas such as home device management, more personalised tariffs and easier debt arrangements. The position for utilities, therefore, should be favourable – finally being seen as working on a more participatory relationship with their customers.

For consumers, the consequences of recession include an increased pressure on household spending. In competitive markets, there could be increased churn as the ever-changing “best-buys” attract customers. For utilities, increased churn rates are obviously bad news – the cost of new customer acquisition often wipes out profit associated with consumption by that customer for months, even years. Moreover, while utilities are working on marketing the best deals to acquire and retain customers – and on piloting smart technologies in the home – consumers’ familiarity with new technologies and their allegiance to some brands presents an opportunity for third parties to gain greater hold on the customer relationship.

Take the case of smart metering, for example, where many utilities are engaging upon pilot and larger rollouts. This is an area of innovation that should deliver benefits to both consumers and utilities. The assured business benefits to the utility companies come not only from applying the technology to lower operational costs, but also from enhancing their brand and customer service reputation. To the customer, smart technologies offer consumption details in an understandable form and give the promise of accurate commodity billing.

The risk is that the potentially lucrative relationship between customer and utility is currently damaged to a point where telecommunications providers, retailers or technology companies could step in with attractive, multi-service offerings. That could relegate the utility to simple supply activities, unable to gain a significant hold in home engagement. Certainly, utilities will still witness savings from automated meter reading and improved billing accuracy, but this commoditisation path for the utility company will limit profitable growth and push them further away from customers. Combine this with increased churn, and suddenly the benefits of smart technology deployment could be wiped out for the utility company.

This is not just an issue associated with smart technologies – the entire customer relationship journey with a utility is under threat from non-utility entrants (See Figure 1). Consider the area of consumer marketing and sign-up. Third parties that simply market other companies’ services have already taken a position in this part of the customer journey by providing Internet sites that allow tariff comparison and online switching of suppliers. The brand awareness of the comparison sites has already begun to gain the trust of the customer and the utility brand becomes more remote – the start of an uneasy decline. Additionally, in receiving fees for bringing customers to utilities, these companies thrive on churn – driving up utility cost and driving an even greater gap into the consumer-utility relationship.

Further credence to the challenges comes in the areas around presentation of information to customers. Any utility information channel will demand attention to “stickiness” when using technology such as the Internet for displaying utility bills and consumption data. This information has to be pushed to consumers in an attractive, understandable, and above all, personal format. Does the traditional utility information quality and flow have enough appeal for the average consumer to repeatedly view over time? It could be argued that third parties have the ability to blend in more diverse information to improve stickiness on, for example, handheld devices that give the consumer other benefits such as telephony, traffic and weather updates.

Customer Experience Risks

Traditionally, utilities are seen as relatively “recession proof,” operating on longer- term cycles than financial and retail markets. It is this long-term view that, coupled with an already disjointed customer relationship, poses a significant risk to utilities in the next two years. Customers will react in the competitive markets to the feeling of being “cornered” in an environment where few utilities truly differentiate themselves on customer service, product, tariff or brand. Research suggests that consumers are driving change in the relationship with their utilities, and it is this change that opens up opportunity for others (“Plugging in the Consumer”, IBM Institute for Business Value, 2007).

Reaction may not come soon; rarely do new entrants come into a recessionary market. But the potential for non-utilities to begin exploiting the gap between customer and utility should be cause for concern.

The parallel of these changes and risks was seen in the telco landline market over the last two decades. Several of the big, former-monopoly landline carriers are now perceived as commodity bandwidth providers, with declining core customer numbers and often-difficult regulatory challenges. Newer, more agile companies have stepped into the role of “owning” the consumer relationship and are tailoring the commodities into appealing packages. The underlying services may still come from the former-monopoly, but the customer relationship is now skewing toward the new entrant.

There are strategies that can be proactively deployed, individually or in combination, that improve the resilience of a utility through a recession, and that indeed redraw the client relationship to the point where profitability can increase without attracting the appearance of excess. These strategies resist the potential demise of the utilities to commodity providers, allowing for a value-add future based on their pervasive presence in the home.

The five steps outlined below revolve around the need to focus on the fundamentals, namely customer relationships and cash:

  1. Know Your Customer. Like most companies, utilities can benefit greatly by knowing more about customers. By engaging upon a strategy of ongoing information collection, customer segmentation and profitability analysis, plans can be put in place to detect and react to customer attrition risks. This includes early identification of changes to a customer’s circumstances, such as the ability to settle debt, allowing the utility to work proactively with the customer to address the issue. An active relationship style will show consumers that utilities care and understand, increasing brand loyalty, and hence, lowering the cost to serve.
  2. Free Up Locked Cash. Although recession-resistant in the short-term, identifying organic sources of improved cash flow can be an important source of funding for utilities that need to invest in improving customer relationships and capabilities. Industry benchmarks indicate that most utilities have opportunities to plug leaks in their working capital processes, with the potential of tapping into a significant and accessible source of free cash flow. For example, consider the traditionally neglected, under-invested area of consumer debt. With the economic downturn, debt levels are likely to rise, and, if unchecked, costs and cash flow will be adversely impacted.

    Focus areas for addressing the issue and freeing up locked cash include:

    • Using process management techniques such as activity-based management or Lean Six Sigma to identify opportunities for performance improvement across the billing, collections and credit-management processes;
    • Focusing on developing the skills and operational structures required to better integrate the meter to cash functions; and
    • Optimizing the use of utility-specific debt tools that work with the core systems.

Additionally, gaining insights through precision analytics to better manage debt functions – similar to best practices in banking and telecommunications – needs to be accelerated.

  1. Focus on the Future. Cost cutting is inevitable by many companies in this economic environment. It is important to understand the medium-to-long-term impact of any cuts on the customer relationship to determine if they could hurt profitability by increasing churn and related cost-to-serve metrics. Thus, utilities must achieve a clear understanding of their baseline performance, and have a predictive decision-making capability that delivers accurate, real-time insights so they can be confident that any actions taken will yield the best results.
  2. Innovate. Utilities traditionally work on longer investment cycles than many other businesses. When compared to consumer-facing industries, that can result in consumer perception that they are lacking innovation. Many consumers readily accept new offerings from retailers, telcos and technology firms, and the promise of a smart home will clearly be of strong commercial interest to these individuals. That’s why utilities must act now to show how they are changing, innovating for the future and putting control into the hands of the consumer. Smart metering programs will help the utilities reposition themselves as innovators. The key will be to use technology in a manner that bonds the customer better with the utility.
  3. Agility is King. Longer investment cycles in the utility sector, combined with the massive scale of operations and investment, often restrict a utilities’ ability to be agile in their business models. The long-term future of many utilities will depend upon being able to react to new consumer, technology and regulatory demands within short timescales. Innovation is only innovative for a short time – businesses need to be ready to embrace and exploit innovation with new business models.

Take Action Now

Many will argue that the current utility programs of change, such as core system replacement, smart metering and improving customer offerings, will be enough to sustain and even enhance the customer relationship. The real benefit, however, will be from building upon the change, moving into new products, delivering personalized services and tariffs, and demonstrating an understanding of individual consumer needs.

Still, utilities may struggle to capture discretionary spending from customers ahead of telcos, retailers, financial firms and others. Simply put, action needs to be taken now to prevent the loss of long-term customer relationships. For utilities, doing more of the same in this dynamic and changing market may simply not be good enough!

References:

  1. Multiple references, especially in the British press, including this one from Energy Saving Trust: http://www.energysavingtrust.org.uk/Resources/Daily-news/Gas-and-Electricity/Probe-demanded-into-energy-rip-off/(energysavingtrust)/20792

Be a People Person

I have to admit it. Despite all the exciting new technologies out there, I am finding myself to be a people person when it comes to building smarter grids and more intelligent utilities. Granted, technology is rapidly developing and the utility industry is finding itself in the middle of more and more automation. However, people – from linemen to consumers – will remain critical components for delivering information-enabled energy.

In the many conversations I have with utilities and other industry thought leaders, we often start out talking about smart technology, but eventually our chats settle on people. People can ultimately make or break even the most promising technologies – from personnel and consumers adopting and using the technology to executives driving technology investments. So, in a world buzzing with new technologies, it is important to reacquaint ourselves with people. This article traces some of my conversations about what an intelligent utility is, how people fit in – both on the consumer and utility personnel side – and what the utility industry can do to better involve people. As is my usual style, I will serve up these critical subjects with a side of humor and perspectives outside the utility industry. So be prepared to learn more about yoga, Nashville, crystal balls and the telecom industry, too.

What Is An Intelligent Utility ?

Before understanding the importance of people, let’s take a moment to understand where people fit into smart grids and intelligent utilities. Utilities are no longer exempt from change. From economic stimulus plans to carbon controls, to the impending electric vehicle flood, we must face the fact that the utility industry will undergo significant changes in the coming years, months and even minutes. Now, it is not so much a question of what changes will happen, but how – and how well – will the utility industry adapt to these changes?

A frequent answer to this question has been a “smart grid,” but most smart grid discussions inevitably lead to these questions:

  • How do we get to a smart grid?
  • When do we know when we are there?
  • What is a smart grid anyway?

These are not easy questions. Many groups define the smart grid, but how can you tell when a utility has one? Better understanding this challenge requires an unusual, but useful comparison: Nashville and Nirodha – a state of mind in yoga. Let’s say you are traveling to Nashville. You would see landmarks that you could only find in Nashville, such as the Grand Ole Opry, B.B. King’s Blues Club and the Bell- South Tower. Smart grid landmarks, however, are harder to come by. Utilities can install smart meters and other smart sensors on their grid, but having these technologies does not necessarily mean they have arrived at a smart grid. To add to the confusion, other smart grid components, such as demand response, distribution automation and more advanced metering, have already been around for years.

Although such technologies can support a smarter grid, the smart grid is more than just acquiring certain technology landmarks. So, although it is a nice place, you shouldn’t just think Nashville when you think smart grid. Think Nirodha. For those of you who aren’t yoga enthusiasts, Nirodha is a state of mind in yoga in which you become more focused and aware of an object. In the case of a utility, the object is primarily the transmission and distribution network. As a utility becomes more aware and ultimately more knowledgeable about its network, it can make better decisions about its operation.

Furthermore, as a company builds more knowledge about its grid, it develops not only a smarter grid, but also a more intelligent utility. An intelligent utility overlays information on energy that goes beyond the transmission and distribution network all the way from generation to end users, maximizing its reliability, affordability and sustainability. Essentially, utilities are delivering information-enabled energy. And technology is just one piece for delivering this sort of energy. Here is a quick run-down of the key components in an intelligent utility:

  • Process & technology: Utility objectives and their impact on business process change and smart technology deployment;
  • Economic models: The challenges and opportunities of new paradigms. So this is not just the changes involved with upgrading a technology – like a customer information or geographic information system – but the changes from initiatives like electrifying transportation and microgrids that could radically alter utility companies and the roles of generators and consumers;
  • Finance: Investment trends associated with smart technologies;
  • Public policy: The impact of politics on energy – including efforts by regulators and legislators. These groups ultimately set up the framework that determines whether and how intelligent initiatives move forward; and
  • People: The knowledge, skills and abilities required for both the workforce and consumers in an information-enabled environment.

Involving Workforce

The rest of this article will take a little bit closer look at the last component – people. As we move toward information-enabled energy, the utility workforce will undergo some significant changes – from new job titles, to new knowledge, skills and abilities (KSAs), to new people joining utility companies from other industries.

Ryan Cook, vice president of the employment services division at Energy Central, has pointed out that “In today’s utilities, employee KSAs are based primarily on providing electrical power as a product. These KSAs support the rules-based, process-oriented, functionally structured, and cost-focused business needs of today’s utility. In the future, however, there will be a massive paradigm shift from providing just a product to providing customers with customizable services and solutions for their unique energy needs. The result will be a shift toward KSAs that support a more agile, innovative, collaborative, cross-functional, service-oriented utility of the future. Employees will need to deal with constantly evolving technology.”

So, digitizing the grid will change personnel needs. We know that much, but the big unknown is how exactly will those needs change? And where is a good crystal ball when you need one? Since my snow globe wasn’t working, I thought about other industries that have gone through a digital revolution, which brought me to the telecom and cable industry. I learned much from Alan Babcock, president of Broadband Training Associates. As this industry digitized its grid over the last 13 years and began to focus more on services as opposed to products, it saw significant workforce changes – touching everyone from field crews, to executives, to marketing folks – that could happen to the utility industry as well.

Out In the Field

Before digitizing the telecom and cable industry, many field crews were still pencil and paper, and some still are today. But digitization changes weren’t just about figuring out how to use a truck-mounted laptop. The workforce has a whole new job to do today. In particular, they now have to troubleshoot new problems on multiple services in the network and become experts at devices on an end user’s premise.

Before digitization, field crews dealt with one service – like video in the cable industry – but now they have to balance multiple services in the same network, including voice, data and video. The decisions you make for one service will ultimately impact the others. So, with multiple services, it changes how you do regular maintenance, how you troubleshoot networks, and how you take the network down to make repairs. On top of that, technicians may not be able to take down certain parts of the network because of service level agreements with customers.

Besides dealing with multiple services, field crews have to better understand the devices that extend into customer premises – including modems for Internet or set-top boxes for cable. It can be embarrassing for a telecom or cable company when the consumer knows more about consumer devices than the technician.

Back In the Office

Digitizing the network not only changed KSAs for field crews, but has changed things in the back office of telecom and cable companies as well. These changes occurred in the areas of marketing, customer service, planning and IT.

  • Marketing to customers: Digitization provides cable and telecom companies with increased visibility into the customer premises. This is not only helpful with determining whether customers have service, but also understanding their entertainment preferences. These companies now better understand what entertainment you watch and when you watch it. Ultimately, they have a lot of information at their disposal to be able to better market to you. Telecom companies, however, weren’t traditionally in the entertainment industry, so better marketing to consumers required a new group of employees from outside telecom.
  • Customer service: Customer service has changed in many ways with the digitization of the telecom and cable industry. With a smarter grid, the utility industry often focuses on benefits that it will bring to the customer representatives in terms of access to more information, but there are other benefits to consider as well. An interesting twist in the telecom and cable industry is that as the network gets more complex, a customer service agent’s job gets somewhat simpler. Essentially, customer service representatives have to recall fewer technical details about the network than they did before. It is not as important that they understand how the networks function because they have better visibility into the premise and have more intelligent systems to walk them through trouble-shooting problems.
  • Capital and strategic planning: Digitization has changed the planning time horizon and knowledge requirements for telecom and cable executives. They must factor in the dizzying technology advancements in the industry; think about the rapid movement from 2G to 3G to 4G networks and beyond. The five-year plan now has to be the three-year plan. From a planning standpoint, they also need to better understand the networks in order to figure out how to best utilize and benefit from services that are enabled by those networks.
  • Designing and maintaining IT systems: Aside from learning how to design and maintain new technologies and systems, the technology personnel in telecom and the cable industry have learned some important lessons as they digitize the networks. The first is to more carefully consider the usefulness of new technologies. If a new technology comes along, it doesn’t mean that it has to be used. If a new technology does make sense to use, technology personnel need to consider the human aspects involved with making that change, including change management and making sure the technology is ready when people actually begin using it.

Involving Customers

Not only will the intelligent utility impact its own personnel, but it will impact consumers as well. In particular, utilities will have to help consumers to understand the value of changes and get them to participate in intelligent initiatives.

As I am sure many of you have realized from conversations with friends and family, many people do not understand smart grid benefits or even how the grid really works. Although more people are starting to realize the value, a key challenge is how to get consumers to grasp these concepts and support a smarter grid and more intelligent utility. Utilities have to figure out how to make these things real for people – and are finding many ways to do that. As one utility executive pointed out, “A technology center served to convince our community stakeholders and our PUC that this appears to be a worthwhile journey. The awareness to the consumer was a tremendous value. They were able to start thinking of the value of what we’re trying to build rather than what we’re trying to build.”

Many intelligent initiatives, from demand response to real-time pricing, focus on the end user and require some level of consumer effort. Consumer participation is key for success, but utilities are finding it challenging to get participation. Solutions range from more automation in controlling household appliances and HVAC systems to competition between neighbors regarding energy consumption, but there is still much work to be done in this area, depending on consumer demographics.

Be A People Person

It is easy to get caught up in the technology hype, but as the examples above demonstrate, it is important to keep people in the equation when looking at smart initiatives. People play a key role in determining their success or failure. By preparing for the people factor and considering them in smart initiatives, utilities can better ensure the adoption and success of new technologies and processes.

A Smart Strategy for a Smart Grid

Every year, utilities are faced with the critical decision of where to invest capital. These decisions are guided by several factors, such as regulatory requirements, market conditions and business strategies. Given their magnitude, decisions are not made hastily. Careful consideration is given to the financial and operational prudence of large capital projects, such as power plants and new infrastructure.

The utility also makes sure that it has the resources to support the implementation and on-going operation of large projects. This discipline is necessary to do what is best for the utility, and ultimately, the customer. This same discipline is essential in assessing the use of smart grid technologies, such as advanced metering infrastructure (AMI), distribution automation (DA) and home area networks (HAN).

In the last several years, the ubiquitous coverage of the smart grid has sparked the interests of many utilities looking to modernize their infrastructures and find new ways to interact with their customers. Most recently, the excitement around smart grid initiatives has accelerated as a result of its inclusion in the U.S. government’s economic stimulus package. However, utilities must remain cautious as they evaluate these new technologies.

The current "rush" can result in a lack of structure around strategy and planning for smart grid improvements. As utilities embrace smart grid technologies, many are tempted to develop a vision and strategies in a hurried, reactionary fashion rather than taking a rigorous, structured approach to determine what technologies will deliver the most value to the utility and its customer base.

Unlike planning for other capital projects, planning for smart grid is not simply about filing a regulatory business case; it is planning a business case for transformation. It is about implementing the right mix of smart grid technologies that delivers the greatest direct (operational savings) and indirect (customer benefits, customer satisfaction, reliability) benefits for the utility. Additionally, proper planning and strategy identifies risks and considerations that facilitate implementation of new technologies. Finally, a structured approach considers the organization’s capacity to complete the project. Just as you wouldn’t approve the construction of a power plant without ensuring that you have the resources to complete it, you shouldn’t begin the smart grid journey without a clear sense of where you are going and how you are going to get there.

A methodical approach to defining a smart grid vision can be accomplished through leadership workshops that define a portfolio of strategic options and establish the criteria to analyze the portfolio’s value (both quantitative and qualitative). These sessions assess the various smart grid technologies to determine what unique mix (technologies and geographies) is the best fit to meet the utility’s objectives.

The key steps to defining a smart grid vision are:

  • Define a decision framework;
  • Develop strategic options;
  • Analyze value; and
  • Ratify strategy.

Ultimately, this approach results in a richer smart grid strategy and decision making process that is consistent with other large capital projects.

Define a Decision Framework

The first step toward defining a smart grid vision is to develop a decision making process to establish the emphasis and focus of the smart grid program. Are upfront capital costs the main concern, or is selecting mature and proven technologies more crucial? Some utilities may seek technologies that can be implemented quickly, while others may be more focused on a multi-year rollout of smart grid initiatives.

Identifying these crucial drivers and understanding their importance is achieved by creating a baseline decision framework to evaluate smart grid technologies. The framework should be shaped by project management, sponsorship and subject matter experts (SMEs) from all functional groups (e.g., transmission and distribution, meter services, billing, call center, human resources, finance and information technology) within the organization. This ensures that the initiative has executive buy-in and input from all groups affected by a smart grid implementation.

A good decision framework incorporates company strategic priorities and consists of both qualitative and quantitative measures. Qualitative factors include customer satisfaction, technology maturity and obsolescence, implementation risks and alignment with business priorities. Quantitative factors examine product and resource costs, and product benefits and savings.

It is also important to understand and compare functionality available to functionality needed. For example, a utility might be interested in implementing HAN capabilities, but may ultimately realize that DA will generate greater value. In the end, the decision framework lays the foundation for the evaluation of a utility’s smart grid portfolio.

Finally, a decision framework should consider and evaluate the program risks and the organization’s ability to successfully execute the project (e.g., timeline, skill set required, availability of resources, competing projects, technological obsolescence/ maturity).

Develop Strategic Options

Smart grid is not a "one size fits all" initiative. Rather than view smart grid as an "all or nothing" proposition, each utility should define its own customized solution. The specific strategy and technologies of a smart grid program is driven by the needs of the utility. For instance, utilities focused on improving grid reliability will emphasize DA technologies, while others more interested in reducing operational costs will emphasize an AMI approach.

Once a decision framework has been created, the utility should begin to assess the advantages and disadvantages of smart grid technologies using a summary scorecard (Figure 1).

These scorecards provide a comprehensive view of the technology and identify risks, dependencies, resource effort, key benefits and costs associated with the technology. Once complete, scorecards can be used to identify different mixtures, or portfolios, of smart grid technology options.

The advantage of assembling technologies into a portfolio is that it enables an enterprise-wide perspective of the program. The value for each stakeholder organization can be identified and evaluated. The integration of smart grid technologies is made more apparent.

When selecting a portfolio, there are a few key points to keep in mind. First, a smart grid portfolio doesn’t have to incorporate all available technologies, only the ones that coincide with the business strategy. Next, smart grid technologies don’t have to be implemented uniformly across the entire service territory. For instance, a utility could elect to utilize substation automation only at critical or less reliable substations, or choose to install AMI meters in jurisdictions/areas where meter reading cost is high.

Finally, timing of the smart grid rollout is critical. A utility doesn’t have to provide all of the functionality on day 1. Subsequent capability releases can be planned many years in the future.

One of the major obstacles to implementing a smart grid program is the lack of maturity in emerging smart grid technologies. Utilities can counter this through the use of interim solutions. An interim solution helps the utility to recognize smart grid benefits in a "manumatic" environment, combining manual business processes and a degree of process and system automation, with the goal to transition to more integration and automation.

Examples of interim solutions include:

  • Advanced Metering Infrastructure (AMI) – If there is no regulatory structure for the use of interval data, a utility could initially use the technology for remote monthly register reads and remote connect/ disconnect with idea to transition to interval-based rates as they become required.
  • Meter Data Management System (MDMS) – If interval data is not yet needed, the utility may be able to defer investment in an MDMS. At a later date, a new CIS system/CIS modifications could provide MDMS functionality.
  • Wide Area Network (WAN) Communications Backhaul – A utility may start with a cellular backhaul and move to another technology (e.g., WiMax) as it evolves.
  • Direct Load Control – Initially, a utility could use a technology independent of AMI (e.g., paging network) and then transition to load control through the AMI meter.

Incorporating interim solutions gives utilities additional flexibility in what technologies can be included in its smart grid portfolio. Once a closer analysis is given to the technology portfolio, utilities can determine if and where interim solutions should be considered.

Analyze Value

Would a utility build a 2 GigaWatt power plant to satisfy a 100 MegaWatt demand? It’s safe to say most wouldn’t. The additional capacity of the plant does not justify the cost. Although this is an obvious example, it demonstrates that utilities have an existing decision process around large capital investments. In order to successfully define a smart grid strategy, utilities must find a way to transition this type of analysis to smart grid technologies. A qualitative and quantitative value analysis of smart grid portfolios will provide justification of which smart grid technologies to implement.

Qualitative review involves scoring the chosen technology portfolio(s) against the decision framework. This provides a sense of how the technologies match the utility’s risk profile, resource constraints and overall strategy. For instance, a utility may see that some technologies are cost-effective, but too risky to implement in the short-term. These factors are not captured in financial modeling and provide key information to aid in the transition from strategic planning to implementation.

Quantitative analysis assures cost effectiveness for smart grid technology portfolio(s) and is achieved through the use of a business case or financial model. This analysis factors in the various costs and benefits of the smart grid portfolio. For instance, a technology portfolio with AMI and DA would indicate significant costs for the purchase and deployment of new devices, but would calculate benefits on improved grid reliability and remote meter reading.

Figure 2 depicts an overview of a financial model that could be used for smart grid value analysis. As the cost-effectiveness of a particular technology portfolio is determined, the utility may find that the portfolio needs to be modified in order to achieve increased savings. For example, an advanced communications infrastructure to implement AMI alone may not be cost effective. However, if the same infrastructure was also used to enable DA and mobile dispatch it would become much more cost effective. The combination of financial data and qualitative options analysis will help the utility to determine the optimal mix of smart grid technologies to implement.

Ratify Strategy

The selection of a smart grid portfolio and the associated value analysis is only the starting point on the journey to a smart grid; it simply puts the building blocks in place for the utility to transition into implementation planning. The final step in developing a smart grid strategy is to understand how the project will be executed. Utilities should begin implementation planning by asking the following key questions:

  • What is the project scope?
  • What are the key success factors?
  • What is the timeline to complete the project?
  • Which technologies do we implement first (priority/critical path)?
  • What resources are going to do the work? What can be done with internal employees vs. consultants and contractors?
  • What are the risks? How will we manage them?
  • What are the key integration points?
  • What are the competing priorities/projects?
  • Are there regulatory constraints?

A final question leadership may want to ask is "What is the largest non-core project the company has ever undertaken?" and "Why was this project successful/ unsuccessful?" Considering this will allow the utility to consider lessons learned and better understand their capacity for change.

Once these questions have been answered, the utility is ready to begin a smart grid deployment roadmap. The purpose of this roadmap is to lay out the key initiatives over the project timeline, noting the key dependencies and integration points. At this point, it is crucial to transition the organization from a strategy focus to an implementation focus. Current project leadership/sponsorship and functional SMEs should not be released from the project, but rather retained to assist with implementation planning and execution in new roles within the utility’s smart grid organization.

For a variety of reasons, a utility may decide not to immediately begin its smart grid implementation once the vision and strategy have been defined. All is not lost as this analysis helps to identify the key drivers, benefits, risks and obstacles associated with the smart grid program. This can be used as a baseline for future analysis or planning once the utility is ready to continue its smart grid journey.

Conclusion

Implementing a smart grid strategy and plan is an enterprise-transforming endeavor. It may be one of the most pervasive programs a utility has ever attempted. It will impact most every energy delivery organization/function; from operations to customer service and from procurement to human resources. The information technology/operations technology boundary will be crossed many times. Appropriate evaluation of the options and alignment with the company’s strategic goals and challenges is perhaps the most critical step in the smart grid journey. Strategic decisions should be based on rigorous analysis of internal and external aspects, and not an industry trend.

Intelligent Communications Platform Provides Foundation for Clean Technology Solutions to Smart Grid

Since the wake-up call of the 2003 blackout in the northeastern United States and Canada, there’s been a steady push to improve the North American power grid. Legislation in both the United States and Canada has encouraged investments in technologies intended to make the grid intelligent and to solve critical energy issues. The Energy Policy Act (EPAct) of 2005 mandated that each state evaluate the business case for advanced metering infrastructure (AMI). In Ontario, the Energy Conservation Responsibility Act of 2006 mandated deployment of smart meters to all consumers by 2010. And the recent U.S. Energy Independence and Security Act of 2007 expands support from the U.S. government for investments in smart grid technologies while further emphasizing the need for the power industry to play a leadership role in addressing carbon dioxide emissions affecting climate change.

Recent state-level legislation and consumer sentiment suggest an increasing appetite for investments in distributed clean-technology energy solutions. Distributed generation technologies such as solar, wind and bio-diesel are becoming more readily available and have the potential to significantly improve grid operations and reliability.

THE NEXT STEP

Although the full vision for the smart grid is still somewhat undefined, most agree that an intelligent communications platform is a necessary foundation for developing and realizing this vision. Of the 10 elements that define the smart grid as contained within the Energy Act of 2007, more than half directly relate to or involve advanced capabilities for advanced communications.

A core business driver for intelligent communications is full deployment of smart metering, also referred to as advanced metering infrastructure. AMI involves automated measurement of time-of-use energy consumption – at either hourly or 15-minute intervals – and provides for new time-of-use rates that encourage consumers to use energy during off-peak hours when generation costs are low rather than peak periods when generation costs are high and the grid is under stress. With time-of-use rates, consumers may continue to use power during high peak periods but will pay a higher price to do so. AMI may also include remote service switch functionality that can reduce costs associated with site visits otherwise required to manage move-out/move-ins or to support prepayment programs.

Other smart grid capabilities that may be easily realized through the deployment of intelligent communications and AMI include improved outage management detection and restoration monitoring, revenue assurance and virtual metering of distribution assets.

CRITICAL ATTRIBUTES OF AMI SOLUTIONS

Modern communications network solutions leverage standards-based technology such as IEEE 802.15.4 to provide robust two-way wireless mesh network communications to intelligent devices. The intelligent communications platform should provide for remote firmware upgrades to connected intelligent devices and be capable of leveraging Internet protocol-based communications across multiple wide-area network (WAN) options (Figure 1).

Critical for maximizing the value of a communications infrastructure investment is support for broad interoperability and interconnectivity. Interoperability for AMI applications means supporting a range of options for metering devices. A communications platform system should be meter manufacturer-independent, empowering choice for utilities. This provides for current and future competitiveness for the meter itself, which is one of the more expensive elements of the smart metering solution.

Interconnectivity for communications platforms refers to the ability to support a broad range of functions, both end-point devices and systems at the head end. To support demand-side management and energy-efficiency initiatives, an intelligent communications platform should support programmable communicating thermostats (PCTs), in-home displays (IHDs) and load control switches.

The system may also support standards-based home-area networks (HANs) such as ZigBee and Zensys. Ultimately an intelligent communications platform should support a model whereby third-party manufacturers can develop solutions that operate on the network, providing competitive options for utilities.

For enterprise system interconnectivity, an AMI demand-side management or other smart grid head-end application should be developed using service-oriented architecture (SOA) principles and Web technologies. These applications should also support modern Web services-based solutions, providing published simple object access protocol (SOAP)-based APIs. This approach provides for easier integration with existing enterprise systems and simplifies the process of adding functionality (either through enhancements provided by the vendor or add-ons delivered by third parties or developed by the utility).

Finally, the value of an intelligent communications platform deployment is driven by the ability of other enterprise applications and processes to utilize the vast amount of new data received through the AMI , demand side management and smart grid applications. Core areas of extended value include integration with customer information systems and call center processes, and integration with outage management and work management systems. In addition, the intelligent communications platform makes utilities much better able to market new offerings to targeted customers based on their energy consumption profiles while also empowering consumers with new tools and access to information. The result: greater control over energy consumption costs and improved satisfaction.

INTEGRATION OF DISTRIBUTED GENERATION RESOURCES

Deployment and integration of distributed generation, including renewable resources, is an important supply-side element of the smart grid vision. This may include the installation of arrays of solar photovoltaic panels on home and office roofs, solar carports, small wind (3-5kvA) turbines, small biogas turbines and fuel cells.

By integrating these resources into a common communications platform, utilities have the opportunity to develop solutions that achieve much greater results than those provided simply by the sum of independent systems. For example, intelligent plug-in hybrid electric vehicles (PHEvs) connected to a smart solar carport may choose when to purchase power for charging the car or even to sell power back to the grid in a vehicle-to-grid (v2G) model based on dynamic price signals received through the communications platform. By maintaining intelligence at the edge of the grid, consumers and distributed resource owners can be empowered to manage to their own benefits and the grid as a whole.

SUMMARY

Now is the time to embark on realizing the smart grid vision. Global warming and system reliability issues are driving a sense of urgency. An intelligent communications platform provides a foundation capable of supporting multiple devices in multiple environments – commercial, industrial and residential – working seamlessly together in a single unified network.

All of the technical assets of a smart grid can be managed holistically rather than as isolated or poorly connected parts. The power of a network grows geometrically according to the amount of resources and assets actively connected to it. This is the future of the smart grid, and it’s available today.

Smart Meters on a Roll in Canada

Electricity supply challenges in Ontario, Canada, have led the provincial government there to take aggressive action on both the supply and demand sides to meet customer electricity needs. Between now and 2025, it’s estimated that Ontario must build an almost entirely new electricity system – including replacing approximately 80 percent of current generating facilities (as they’re retired over time) and expanding the system to meet future growth. However, just as building new supply is vital, so too is conservation. That’s why Ontario’s provincial government is introducing new tools like smart meters to encourage electricity consumers to think more about how and when they use electricity. By implementing a smart metering infrastructure by 2010, the province hopes to provide a foundation for achieving a more than five percent reduction in provincial demand through load shifting, energy savings and price awareness.

Hydro One owns and operates one of the 10 largest transmission and distribution systems in North America, serving a geographic area of about 640,000 square kilometers. As the leading electricity transmitter and distributor in Ontario, the company supports the province’s goal of creating a conservation culture in Ontario and having a smart meter in every Ontario home and small business. The company’s allocation of the province’s target was 240,000 smart meters by 2007 and the full 1.3 million by 2010.

The task for Hydro One and other local distribution companies (LDCs) in the province is to meet the government time line while at the same time building an enabling solution that provides the most upside for operations, demand management and customer satisfaction. Working with the industry regulator and the LDCs, phased goals were established and allocated among the major utilities in the province.

ADVANCED METERING INFRASTRUCTURE AND SOLUTION ARCHITECTURE

Advanced metering infrastructure (AMI) is the term used to describe all of the hardware, software and connectivity required for a fully functioning smart metering system. To view AMI as just a technology to remotely read meters and bill customers, however, would be to miss the full potential of smart metering.

The core of the solution resides with the requirement for a ubiquitous communications network and an integration approach that provides for the exploitation of data from many types of devices (automated meter reading, load control, in-home displays, distribution monitoring and control and so on) by making it available to numerous enterprise applications (for example, customer information, outage management, asset management, geographic information and work execution systems).

To meet this requirement, the Hydro One team architected an end-to-end solution that rigorously sought open standards and the use of IP at all communications levels to ensure that the network and integration would be available to and compatible with numerous applications.

Hydro One’s AMI solution is based on standards (ANSI and IEEE) and open protocols (Zigbee and IP) to ensure maximum flexibility into the future as the technology and underlying applications such as in-home energy conservation devices (two-way real-time monitors, pool pump timers and so on) and various utility applications evolve.

Smart Meters

The “smarts” in any smart meter can be housed in virtually any meter platform. Meter reads are communicated at a frequency of 2.4 GHz by a radio housed under the meter’s glass. In essence, the hourly meter reads are transmitted by hopping from one meter to the next, forming a self-organizing network that culminates at the advanced meter regional collector (AMRC). This type of local area network, or LAN, is known as a mesh network and is known for its self-healing characteristics: if communication between meters is interrupted for any reason, communication paths between meters are automatically rerouted to the regional collector to ensure that data is delivered reliably and on time. The installed smart meters also have a “super capacitor,” enabling the meter to send a last communication to the utility when there has been a power outage.

Repeaters

Repeaters provide a wireless range extender for the meters and are used in less densely populated areas in the province to allow data to be transmitted from one meter to the next. Typically, repeaters are needed if the hop between meters is greater than 1 to 2 kilometers (depending on a number of factors, including terrain and ground cover).

Advanced Metering Regional Collectors

Typically installed on poles at preselected locations within a local area network, advanced metering regional collectors (AMRCs) gather the meter readings in a defined area. Most importantly, the AMRCs provide access to the wide area network (WAN), where data is sent wirelessly back to Hydro One. The AMI solution is designed to accommodate either wireless cellular or broadband WAN to backhaul hourly meter reads to the advanced metering control computer.

Advanced Metering Control Computer

The advanced metering control computer (AMCC) is used to retrieve and temporarily store meter reads from the regional collectors before they’re transmitted to the meter data management repository (discussed below). The information stored in the AMCC is available to log maintenance and data transmission faults, and to issue reports on the overall health of the AMI system.

Meter Data Management Repository

MDM/R is the acronym for the province-wide meter data management repository. The MDM/R provides a common infrastructure for receiving meter reads from all LDCs in Ontario, processing the reads to produce billing quality consumption data, and storing and managing the data. The Ontario government has entered into an agreement with the Independent Electricity System Operator to coordinate and manage implementation activities associated with the MDM/R.

Billing

Time-of-use “bucketed” data is sent from the MDM/R to Hydro One for any exception handling that may be required and for customer billing. Hydro One prepares the bill and sends it to the customer for payment.

Web Presentment of Customer Usage Data

Customer electricity usage data will be available to customers by 9 a.m. the day after they use it via a secure website. This data will be clearly marked as preliminary data until the customer has been billed.

GOALS, OBJECTIVES AND KEY ACCOMPLISHMENTS

To successfully deploy the smart metering solution described above, the Hydro One team set out to accomplish the following goals and objectives (which are enshrined in project governance plans and daily project activities):

  • Balance investment with the regulatory process to ensure that smart meter investments don’t get ahead of changes in regulatory requirements.
  • Design, test, prototype and pilot prior to buying or building – a rule that applies to all aspects of the smart meter solution architecture, from the meters and communication network to the back-office systems.
  • Delay building solution components until line-of-business requirements are locked down. Solution components that are unlikely to change will be built before other components to minimize the risk of rework.
  • Test smart meter deployment business processes, technology and customer experience throughout the process.
  • Ensure positive customer experience and value, including providing customers with information and tools to leverage smart meters in an appropriate time frame.
  • Use commercial, off-the-shelf (COTS) products where possible (as opposed to custom solutions).
  • Include estimation of total cost of ownership (one-time and ongoing costs) in architectural decision making.
  • Enable commencement of time-of-use (TOU) billing in 2009.

Key project accomplishments to date have included:

  • Building an in-situ lab using WiMax and meters in rural areas to test and confirm open protocols, wireless broadband interoperability, and meter performance;
  • Conducting a community rollout of about 15,000 meters to develop and successfully test and optimize meter change automation tools and customer communication processes;
  • Mass deploying of just over a quarter of a million meters across the province;
  • Designing and beginning to build the communication network to support the collection of hourly reads from approximately 1.3 million customers.

METER AND NETWORK DEPLOYMENT

Meter installation teams surpassed a notable milestone of 250,000 installed smart meters as of December 2007. Network deployment began in 2007 with a planned ramp-up in 2008 of installing more than 2,000 AMRCs province-wide.

Meeting these targets has required well-coordinated activities across the project team while working in parallel with external entities such as MeasurementCanada and others to ensure compliance with regulatory requirements.

Throughout meter and network deployment activities, Hydro One has adhered closely to three primary guiding principles, namely:

Safety. The following initiatives were factored into the project to help maintain a safe environment for all employees and business partners:

  • Internal training was integrated into the project from the inception, establishing a thorough yet common-sense compliant safety attitude throughout the team.
  • No employee is permitted to work on the project without a full safety refresher.
  • Safety represented a key element of incentive compensation for management and executive personnel.

Customer service. Given the opportunity to visit literally every customer, the success of this project is being judged daily by the manner in which the project team interacts with customers.

  • Every customer is provided with an information package within 15 to 30 days of the meter change.
  • Billing windows are scrupulously avoided through automation tools and integration to CIS in order to eliminate any disruption to the size, look and feel of the customer bill.
  • All customers receive a personal knock at the door before meter change.
  • All life-safety customers are changed by appointment or have positive contact made prior to meter change if they cannot be reached for an appointment

Productivity. Despite Hydro One’s rural footprint – which includes some areas so remote they must be accessed by all-terrain vehicle, boat or snowmobile – the installation teams maintain an average of 39.6 meters per installer-day with a peak of 97 per installer-day. They have achieved this through automation and a phased ramp-up of installers, including training and joint fieldwork with Hydro One’s partners.

IN-HOME CONSERVATION AND DEMAND MANAGEMENT

Testing will soon be underway using third-party devices for residential demand response programs that operate on the mesh network, including two-way realtime monitors, automated thermostats and load control devices. Optimally for customers, meters will serve as the key head-end device, connectable to numerous other devices within the home as illustrated in Figure 2.

While much of this technology is still in its infancy, North America-wide AMI deployments will rapidly accelerate resulting in greatly enhanced customer service opportunities going forward.

LEVERAGING THE SMART NETWORK TO INCREASE UTILITY EFFICIENCY

Hydro One is also looking ahead to applications that will leverage the smart metering communication network to increase the efficiency of its operations. As illustrated in Figure 3, these applications include distribution station monitoring, enhancements to outage management, safety monitoring, mobile work dispatch and work accomplishment, and asset security. All of the above applications have been tested in a proof-of-concept environment, and individual projects are planned to proceed on a business case basis.

Policy and Regulatory Initiatives And the Smart Grid

Public policy is commonly defined as a plan of action designed to guide decisions for achieving a targeted outcome. In the case of smart grids, new policies are needed if smart grids are actually to become a reality. This statement may sound dire, given the recent signing into law of the 2007 Energy Independence and Security Act (EISA) in the United States. And in fact, work is underway in several countries to encourage smart grids and smart grid components such as smart metering. However, the risk still exists that unless stronger policies are enacted, grid modernization investments will fail to leverage the newer and better technologies now emerging, and smart grid efforts will never move beyond demonstration projects. This would be an unfortunate result when you consider the many benefits of a true smart grid: cost savings for the utility, reduced bills for customers, improved reliability and better environmental stewardship.

REGIONAL AND NATIONAL EFFORTS

As mentioned above, several regions are experimenting with smart grid provisions. At the national level, the U.S. federal government has enacted two pieces of legislation that support advanced metering and smart grids. The Energy Policy Act of 2005 directed U.S. utility regulators to consider time-of-use meters for their states. The 2007 EISA legislation has several provisions, including a list of smart grid goals to encourage two-way, real-time digital networks that stretch from a consumer’s home to the distribution network. The law also provides monies for regional demonstration projects and matching grants for smart grid investments. The EISA legislation also mandates the development of an “interoperability framework.”

In Europe, the European Union (E.U.) introduced a strategic energy technology plan in 2006 for the development of a smart electricity system over the next 30 years. The European Technology Platform organization includes representatives from industry, transmission and distribution system operators, research bodies and regulators. The organization has identified objectives and proposes a strategy to make the smart grid vision a reality.

Regionally, several U.S. states and Canadian provinces are focused on smart grid investments. In Canada, the Ontario Energy Board has mandated smart meters, with meter installation completion anticipated by 2010. In Texas, the Public Utilities Commission of Texas (PUCT) has finalized advanced metering legislation that authorizes metering cost recovery through surcharges. The PUCT also stipulated key components of an advanced metering system: two-way communications, time-date stamp, remote connect/disconnect, and access to consumer usage for both the consumer and the retail energy provider. The Massachusetts State Senate approved an energy bill that includes smart grid and time-of-use pricing. The bill requires that utilities submit a plan by Sept. 1, 2008, to the Massachusetts Public Utilities Commission, establishing a six-month pilot program for a smart grid. Most recently, California, Washington state and Maryland all introduced smart grid legislation.

AN ENCOMPASSING VISION

While these national and regional examples represent just a portion of the ongoing activity in this area, the issue remains that smart grid and advanced metering pilot programs do not guarantee a truly integrated, interoperable, scalable smart grid. Granted, a smart grid is not achieved overnight, but an encompassing smart grid vision should be in place as modernization and metering decisions are made, so that investment is consistent with the plan in mind. Obviously, challenges – such as financing, system integration and customer education – exist in moving from pilot to full grid deployment. However, many utility and regulatory personnel perceive these challenges to be ones of costs and technology readiness.

The costs are considerable. KEMA, the global energy consulting firm, estimates that the average cost of a smart meter project (representing just a portion of a smart grid project) is $775 million. The E.U.’s Strategic Energy Technology Plan estimates that the total smart grid investment required could be as much as $750 billion. These amounts are staggering when you consider that the market capitalization of all U.S. investor-owned electric utilities is roughly $550 billion. However, they’re not nearly as significant when you subtract the costs of fixing the grid using business-as-usual methods. Transmission and distribution expenditures are occurring with and without intelligence. The Energy Information Administration (EIA) estimates that between now and 2020 more than $200 billion will be spent to maintain and expand electricity transmission and distribution infrastructures in the United States alone.

Technology readiness will always be a concern in large system projects. Advances are being made in communication, sensor and security technologies, and IT. The Federal Communications Commission is pushing for auctions to accelerate adoption of different communication protocols. Price points are decreasing for pervasive cellular communication networks. Electric power equipment manufacturers are utilizing the new IEC 61850 standard to ensure interoperability among sensor devices. vendors are using approaches for security products that will enable north American Electric Reliability Corp. (nERC) and critical infrastructure protection (CIP) compliance.

In addition, IT providers are using event-driven architecture to ensure responsiveness to external events, rather than processing transactional events, and reaching new levels with high-speed computer analytics. leading service-oriented architecture companies are working with utilities to establish the underlying infrastructure critical to system integration. Finally, work is occurring in the standards community by the E.U., the Gridwise Architecture Council (GAC), Intelligrid, the national Energy Technology laboratory (nETl) and others to create frameworks for linking communication and electricity interoperability among devices, systems and data flows.

THE TIME IS NOW

These challenges should not halt progress – especially when one considers the societal benefits. Time stops for no one, and certainly in the case of the energy sector that statement could not be more accurate. Energy demand is increasing. The Energy Information Administration estimates that annual energy demand will increase roughly 50 percent over the next 25 years. Meanwhile, the debate over global warming seems to have waned. Few authorities are disputing the escalating concentrations of several greenhouse gases due to the burning of fossil fuels. The E.U. is attempting to decrease emissions through its 2006 Energy Efficiency directive. Many industry observers in the United States believe that there will likely be federal regulation of greenhouse gases within the next three years.

A smart grid would address many of these issues, giving options to the consumer to manage their usage and costs. By optimizing asset utilization, the smart grid will provide savings in that there is less need to build more power plants to meet increased electricity demand. As a self-healing grid that detects, responds and restores functions, the smart grid can greatly reduce the economic impact of blackout and power interruption grid failures.

A smart grid that provides the needed power quality can ensure the strong and resilient energy infrastructure necessary for the 21st-century economy. A smart grid also offers consumers options for managing their usage and costs. Further, a smart grid will enable plug-and-play integration of renewables, distributed resources and control systems. lastly, a smart grid will better enable plug-and-play integration of renewables, distributed resources and control systems.

INCENTIVES FOR MODERNIZATION

despite all of these potential benefits, more incentives are needed to drive grid modernization efforts. Several mechanisms are available to encourage investment. Some utilities are already using or evaluating alternative rate structures such as net metering and revenue decoupling to give utilities and consumer incentives to use less energy. net metering awards energy incentives or credit for consumer-based renewables. And revenue decoupling is a mechanism designed to eliminate or reduce dependence of a utility’s revenues on sales. Other programs – such as energy-efficiency or demand-reduction incentives – motivate consumers and businesses to adopt long-term energy-efficient behaviors (such as using programmable thermostats) and to consider energy efficiency when using appliances and computers, and even operating their homes.

Policy and regulatory strategy should incorporate these means and include others, such as accelerated depreciation and tax incentives. Accelerated depreciation encourages businesses to purchase new assets, since depreciation is steeper in the earlier years of the asset’s life and taxes are deferred to a later period. Tax incentives could be put in place for purchasing smart grid components. Utility Commissions could require utilities to consider all societal benefits, rather than just rate impacts, when crafting the business case. Utilities could take federal income tax credits for the investments. leaders could include smart grid technologies as a critical component of their overall energy policy.

Only when all of these policies and incentives are put in place will smart grids truly become a reality.

SmartGridNet Architecture for Utilities

With the accelerating movement toward distributed generation and the rapid shift in energy consumption patterns, today’s power utilities are facing growing requirements for improved management, capacity planning, control, security and administration of their infrastructure and services.

UTILITY NETWORK BUSINESS DRIVERS

These requirements are driving a need for greater automation and control throughout the power infrastructure, from generation through the customer site. In addition, utilities are interested in providing end-customers with new applications, such as advanced metering infrastructure (AMI), online usage reports and outage status. In addition to meeting these requirements, utilities are under pressure to reduce costs and automate operations, as well as protect their infrastructures from service disruption in compliance with homeland security requirements.

To succeed, utilities must seamlessly support these demands with an embedded infrastructure of traditional devices and technologies. This will allow them to provide a smooth evolution to next-generation capabilities, manage life cycle issues for aging equipment and devices, maintain service continuity, minimize capital investment, and ensure scalability and future-proofing for new applications, such as smart metering.

By adopting an evolutionary approach to an intelligent communications network (SmartGridNet), utilities can maximize their ability to leverage the existing asset base and minimize capital and operations expenses.

THE NEED FOR AN INTELLIGENT UTILITY NETWORK

As a first step toward implementing a SmartGridNet, utilities must implement intelligent electronic devices (IEDs) throughout the infrastructure – from generation and transmission through distribution directly to customer premises – if they are to effectively monitor and manage facilities, load and usage. A sophisticated operational communications network then interconnects such devices through control centers, providing support for supervisory control and data acquisition (SCADA), teleprotection, remote meter reading, and operational voice and video. This network also enables new applications such as field personnel management and dispatch, safety and localization. In addition, the utility’s corporate communications network increases employee productivity and improves customer service by providing multimedia; voice, video, and data communications; worker mobility; and contact center capabilities.

These two network types – operational and corporate – and the applications they support may leverage common network facilities; however, they have very different requirements for availability, service assurance, bandwidth, security and performance.

SMARTGRIDNET REQUIREMENTS

Network technology is critical to the evolution of the next-generation utility. The SmartGridNet must support the following key requirements:

  • Virtualization. Enables operation of multiple virtual networks over common infrastructure and facilities while maintaining mutual isolation and distinct levels of service.
  • Quality of service (QoS). Allows priority treatment of critical traffic on a “per-network, per-service, per-user basis.”
  • High availability. Ensures constant availability of critical communications, transparent restoration and “always on” service – even when the public switched telephony network (PSTN) or local power supply suffers outages.
  • Multipoint-to-multipoint communications. Provides integrated control and data collection across multiple sensors and regulators via synchronized, redundant control centers for disaster recovery.
  • Two-way communications. Supports increasingly sophisticated interactions between control centers and end-customers or field forces to enable new capabilities, such as customer sellback, return or credit allocation for locally stored power; improved field service dispatch; information sharing; and reporting.
  • Mobile services. Improves employee efficiency, both within company facilities and in the field.
  • Security. Protects the infrastructure from malicious and inadvertent compromise from both internal and external sources, ensures service reliability and continuity, and complies with critical security regulations such as North American Electric Reliability Corp. (NERC).
  • Legacy service integration. Accommodates the continued presence of legacy remote terminal units (RTUs), meters, sensors and regulators, supporting circuit, X.25, frame relay (FR), and asynchronous transfer mode (ATM) interfaces and communications.
  • Future-proofing. Capability and scalability to meet not just today’s applications, but tomorrow’s, as driven by regulatory requirements (such as smart metering) and new revenue opportunities, such as utility delivery of business and residential telecommunications (U-Telco) services.

SMARTGRIDNET EVOLUTION

A number of network technologies – both wire-line and wireless – work together to achieve these requirements in a SmartGridNet. Utilities must leverage a range of network integration disciplines to engineer a smooth transformation of their existing infrastructure to a SmartGridNet.

The remainder of this paper describes an evolutionary scenario, in which:

  • Next-generation synchronous optical network (SONET)-based multiservice provisioning platforms (MSPPs), with native QoS-enabled Ethernet capabilities are seamlessly introduced at the transport layer to switch traffic from both embedded sensors and next-generation IEDs.
  • Cost-effective wave division multiplexing (WDM) is used to increase communications network capacity for new traffic while leveraging embedded fiber assets.
  • Multiprotocol label switching (MPLS)/ IP routing infrastructure is introduced as an overlay on the transport layer only for traffic requiring higher-layer services that cannot be addressed more efficiently by the transport layer MSPPs.
  • Circuit emulation over IP virtual private networks (VPNs) is supported as a means for carrying sensor traffic over shared or leased network facilities.
  • A variety of communications applications are delivered over this integrated infrastructure to enhance operational efficiency, reliability, employee productivity and customer satisfaction.
  • A toolbox of access technologies is appropriately applied, per specific area characteristics and requirements, to extend power service monitoring and management all the way to the end-customer’s premises.
  • A smart home network offers new capabilities to the end-customer, such as Advanced Metering Infrastructure (AMI), appliance control and flexible billing models.
  • Managed and assured availability, security, performance and regulatory compliance of the communications network.

THE SMARTGRIDNET ARCHITECTURE

Figure 1 provides an architectural framework that we may use to illustrate and map the relevant communications technologies and protocols.

The backbone network in Figure 1 interconnects corporate sites and data centers, control centers, generation facilities, transmission and distribution substations, and other core facilities. It can isolate the distinct operational and corporate communications networks and subnetworks while enforcing the critical network requirements outlined in the section above.

The underlying transport network for this intelligent backbone is made up of both fiber and wireless (for example, microwave) technologies. The backbone also employs ring and mesh architectures to provide high availability and rapid restoration.

INTELLIGENT CORE TRANSPORT

As alluring as pure packet networks may be, synchronous SONET remains a key technology for operational backbones. Only SONET can support the range of new and legacy traffic types while meeting the stringent absolute delay, differential delay and 50-millisecond restoration requirements of real-time traffic.

SONET transport for legacy traffic may be provided in MSPPs, which interoperate with embedded SONET elements to implement ring and mesh protection over fiber facilities and time division multiplexing (TDM)-based microwave. Full-featured Ethernet switch modules in these MSPPs enable next-generation traffic via Ethernet over SONET (EOS) and/or packet over SONET (POS). Appropriate, cost-effective wave division multiplexing (WDM) solutions – for example, coarse, passive and dense WDM – may also be applied to guarantee sufficient capacity while leveraging existing fiber assets.

BACKBONE SWITCHING/ROUTING

From a switching and routing perspective, a significant amount of traffic in the backbone may be managed at the transport layer – for example, via QoS-enabled Ethernet switching capabilities embedded in the SONET-based MSPPs. This is a key capability for supporting expedited delivery of critical traffic types, enabling utilities to migrate to more generic object-oriented substation event (GOOSE)-based inter-substation communications for SCADA and teleprotection in the future in accordance with standards such as IEC 61850.

Where higher-layer services – for example, IP VPN, multicast, ATM and FR – are required, however, utilities can introduce a multi-service switching/routing infrastructure incrementally on top of the transport infrastructure. The switching infrastructure is based on multi-protocol label switching (MPLS), implementing Layer 2 transport encapsulation and/or IP VPNs, per the relevant Internet engineering task force (IETF) requests for comments (RFCs).

This type of unified infrastructure reduces operations costs by sharing switching and restoration capabilities across multiple services. Current IP/MPLS switching technology is consistent with the network requirements summarized above for service traffic requiring higher-layer services, and may be combined with additional advanced services such as Layer 3 VPNs and unified threat management (UTM) devices/firewalls for further protection and isolation of traffic.

CORE COMMUNICATIONS APPLICATIONS

Operational services such as tele-protection and SCADA represent key categories of applications driving the requirements for a robust, secure, cost-effective network as described. Beyond these, there are a number of communications applications enabling improved operational efficiency for the utility, as well as mechanisms to enhance employee productivity and customer service. These include, but are not limited to:

  • Active network controls. Improves capacity and utilization of the electricity network.
  • Voice over IP (VoIP). Leverages common network infrastructure to reduce the cost of operational and corporate voice communications – for example, eliminating costly channel banks for individual lines required at remote substations.
  • Closed circuit TV (CCTV)/Video Over IP. Improves surveillance of remote assets and secure automated facilities.
  • Multimedia collaboration. Combines voice, video and data traffic in a rich application suite to enhance communication and worker productivity, giving employees direct access to centralized expertise and online resources (for example, standards and diagrams).
  • IED interconnection. Better measures and manages the electricity networks.
  • Mobility. Leverages in-plant and field worker mobility – via cellular, land mobile radio (LMR) and WiFi – to improve efficiency of key work processes.
  • Contact center. Employs next-generation communications and best-in-class customer service business processes to improve customer satisfaction.

DISTRIBUTION AND ACCESS NETWORKS

The intelligent utility distribution and access networks are subtending networks from the backbone, accommodating traffic between backbone switches/applications and devices in the distribution infrastructure all the way to the customer premises. IEDs on customer premises include automated meters and device regulators to detect and manage customer power usage.

These new devices are primarily packet-based. They may, therefore, be best supported by packet-based access network technologies. However, for select rings, TDM may also be chosen, as warranted. The packet-based access network technology chosen depends on the specifics of the sites to be connected and the economics associated with that area (for example, right of way, customer densities and embedded infrastructure).

Regardless of the access and last-mile network designs, traffic ultimately arrives at the network via an IP/MPLS edge switch/router with connectivity to the backbone IP/MPLS infrastructure. This switching/routing infrastructure ensures connectivity among the intelligent edge devices, core capabilities and control applications.

THE SMART HOME NETWORK

A futuristic home can support many remotely controlled and managed appliances centered on lifestyle improvements of security, entertainment, health and comfort (see Figure 2). In such a home, applications like smart meters and appliance control could be provided by application service providers (ASPs) (such as smart meter operators or utilities), using a home service manager and appropriate service gateways. This architecture differentiates between the access provider – that is, the utility/U-Telco or other public carrier – and the multiple ASPs who may provide applications to a home via the access provider.

FLEXIBLE CHARGING

By employing smart meters and developing the ability to retrieve electricity usage data at regular intervals – potentially several readings per hour – retailers could make billing a significant competitive differentiator. detailed usage information has already enabled value-added billing in the telecommunications world, and AMI can do likewise for billing electricity services. In time, electricity users will come to expect the same degree of flexible charging with their electricity bill that they already experience with their telephone bills, including, for example, prepaid and post-paid options, tariff in function of time, automated billing for house rental (vacation), family or group tariffs, budget tariffs and messaging.

MANAGING THE COMMUNICATIONS NETWORK

For utilities to leverage the communications network described above to meet business key requirements, they must intelligently manage that network’s facilities and services. This includes:

  • Configuration management. Provisioning services to ensure that underlying switching/routing and transport requirements are met.
  • Fault and performance management. Monitoring, correlating and isolating fault and performance data so that proactive, preventative and reactive corrective actions can be initiated.
  • Maintenance management. Planning of maintenance activities, including material management and logistics, and geographic information management.
  • Restoration management. Creating trouble tickets, dispatching and managing the workforce, and carrying out associated tracking and reporting.
  • Security management. Assuring the security of the infrastructure, managing access to authorized users, responding to security events, and identifying and remediating vulnerabilities per key security requirements such as NERC.

Utilities can integrate these capabilities into their existing network management infrastructures, or they can fully or partially outsource them to managed network service providers.

Figure 3 shows how key technologies are mapped to the architectural framework described previously. Being able to evolve into an intelligent utilities network in a cost-effective manner requires trusted support throughout planning, design, deployment, operations and maintenance.

CONCLUSION

Utilities can evolve their existing infrastructures to meet key SmartGridnet requirements by effectively leveraging a range of technologies and approaches. Through careful planning, designing, engineering and application of this technology, such firms may achieve the business objectives of SmartGridnet while protecting their current investments in infrastructure. Ultimately, by taking an evolutionary approach to SmartGridnet, utilities can maximize their ability to leverage the existing asset base as well as minimize capital and operations expenses.

Trilliant: Advanced Metering Infrastructure Solutions for Utilities and Green Energy Markets

Trilliant Incorporated provides wireless network solutions and software for advanced metering, demand response, smart grid and submetering. With more than 20 years’ experience solving utility meter communications needs, the company empowers flexibility and choice through the adoption and integration of open standards-based technologies.

ADVANCED METERING

Trilliant SecureMesh™ AMI solutions enable utilities to introduce services and programs such as time-of-use (TOU) metering, CIS initiated real-time meter reads and customer disconnect/ reconnect. These programs are transforming the traditional customer-utility relationship through interval-based consumption data and two-way messaging, resulting in reduced operational costs and improved reliability.

DEMAND RESPONSE

Many utilities are initiating smart metering and AMI programs with a primary goal of ad dressing critical peak demand challenges using TOU pricing, critical peak pricing and demand response programs. Trilliant is the first AMI supplier to provide an open standards-based platform for AMI-integrated demand response (i.e., load control) incorporating smart thermostats – and thus air conditioning equipment – and other loads such as pool pumps and water heaters. The Trilliant Demand Response solution also supports in-premise (“in-home”) displays that offer consumers real-time information on energy usage and utility-initiated messages.

SMART GRID

By leveraging Smart Grid solutions from Trilliant, utilities can realize dramatic improvements in system performance and cost. System operational challenges such as outage detection and restoration verification are supported through a combination of network-based intelligence and operations center applications. Trilliant’s Smart Grid solutions enable operations to more effectively identify faults and rapidly restore service on the basis of real-time readings of on-premise conditions. These offerings may also be integrated with extended enterprise systems supporting the mobile field force. Smart Grid solutions from Trilliant provide the foundation for advanced applications such as utility asset life cycle management and others that can benefit from the use of actual loading data.

SUBMETERING

Trilliant Energy Services offerings include turnkey submetering solutions, utility data profiling and online presentment to meet the needs of electric and natural gas utilities. Because Trilliant is an expert in energy technology the company’s solutions offer benefits to all stakeholders – from condo developers and corporations to owners and managers and directly to residential suite owners.