Surviving the Turmoil

With the new administration talking about a trillion dollars of infrastructure investment, the time for the intelligent utility of the future is now. Political pressure and climate change are going to drive massive investments in renewable and clean energy and smart grid technology. These investments will empower customers through the launch and adoption of demand response and energy efficiency programs.

Many believe that the utility industry will change more in the next five years than the previous 50. The greatest technological advancements are only valuable if they can enable desired business outcomes. In a world of rapidly changing technology it is easy to get caught up in the decisions of what to put in, how, when, and where – making it easy to forget why.

A New Era Emerges

The utility industry has, for decades, been the sleeping giant of the U.S. economy. Little has changed in service delivery and consumer options over the last 50 years. But a perfect storm of legislation, funding and technology has set in motion new initiatives that will change the way customers use and think about their utility service. The American Recovery and Reinvestment Act allocates more than $4 billion, via the Smart Grid Investment Grant Program, for development and upgrade of the electrical grid. Simultaneously, significant strides in smart metering technology make the prospect of a rewired grid more feasible.

While technological advances toward the intelligent utility are exciting, technology in and of itself is not the solution for the utility of the future. How those technologies are applied to supporting business outcomes will be key to success in a consumer-empowered environment. Those outcomes must include considerations such as increasing or sustaining customer service levels and reducing bad debt through innovative charging methods and better control of consumption patterns.

Facing New Challenges

Future smart grid considerations aside, consumer expectations are already undergoing transformation. Although some energy prices have decreased recently in light of declining natural gas prices, the long-term trend indicates rates will continue to climb. Faced with increasing energy costs and declining household incomes, customers are looking for options to reduce their utility bill. Further, utilities’ ability to meet demand during peak periods is often inadequate. According to the Galvin Electricity Initiative, “Each day, roughly 500,000 Americans spend at least two hours without electricity in their homes and businesses. Such outages cost at least $150 billion a year. The future looks even worse. Without substantial innovation and investment, rolling blackouts and soaring power bills will become a persistent fact of life [1].”

Simultaneously, environmental concerns are influencing a greater number of consumers than in the past. In April 2009, the U.S. Environmental Protection Agency (EPA) announced it had identified six greenhouse gases that may endanger public health or welfare [2]. According to the EPA, the process of generating electricity creates 41 percent of all carbon dioxide emissions in the U.S. Utilities are under pressure to offer ways to reduce the impact of fossil fuels to accommodate rapidly changing economic and social conditions.

Strategies such as rate structures that incent customers to schedule their energy-intensive activities during off-peak times would help the utility to avoid, or reduce, reliance on the facilities that produce greenhouse gases. Lowering a residential thermostat by just 2 degrees reduces reliance on less desirable sources of generation. According to McKinsey &
Company, carbon dioxide emissions can be reduced by 34 percent in the residential sector alone through enhanced energy productivity [3].

If a significant number of residential consumers could reschedule their peak usage today, it would extend the life of the current infrastructure and reduce the need to raise rates in order to fund capital investments. But at present, in most jurisdictions there is no demonstrable incentive, such as rate structures that reward off-peak usage, to motivate consumers to conserve in any meaningful way.

Aging CIS

Those utilities saddled with aging customer information systems (CIS) – and those executives who have been reluctant to adopt new technology – will be challenged to adapt to the new paradigm. Even utilities with a relatively new CIS in place may find themselves with technology not suited to today’s world. Typically, utilities have been “load serving entities” – matching supply to demand. In the new recession-prone environment, proactive utilities will need to encourage conservation to match supply. Most utilities do not have the capability to show consumers how and when they can save money by using electricity during off-peak hours.

Until utilities can address these needs, and answer customer inquiries about how to save money and energy, they will not be in a position to focus on desired business outcomes. Currently, many utilities track quantitative performance indicators, not business outcomes.

Desired Business Outcomes

Determining the tools, processes or intellectual property needed to achieve desired business outcomes can be a dilemma. Realizing targeted results may require out-of-the-box thinking. To leverage best-in-class practices, many utilities seek external expertise ranging from advisory and consulting resources to a fully outsourced solution.

When addressing the changes the future utility faces, it is easy to become focused on the what, how, when and where to deploy emerging technology rather than the most important element – why deploy at all? Figure 1 depicts Vertex’s four-level solutions approach to business outcomes as an example of keeping the focus on the “why.”

Level 1: Identify Business Challenges. What are the key issues your organization is grappling with? They may be part of the macro trends impacting the industry as a whole or they may be specific to your company. The list might include issues such as substantial bad debt, poor customer satisfaction, declining revenue and profits, high operating cost to serve, and customer acquisition and retention.

Level 2: Identify Desired Outcomes. While acting on business challenges is an integral part of the process, the desired business outcomes are the drivers that will guide you to the solution. At the same time, the solution will also determine if the desired outcomes can be achieved with in-house resources or if an experienced third party should join the team. The solution will also clarify whether you have the technology to realize the desired outcomes or if an investment will be necessary. For example, desired outcomes might include reducing bad debt by 10 percent, improving customer satisfaction from the second quartile to the first quartile, or eliminating 30 percent of the cost of the meter-to-cash process. One or more of these outcomes may require new supporting technology.

Level 3: Develop and Implement Solution. Once the specific business challenges have been fully discussed and the desired outcomes outlined, the next step requires designing the solution to enable achievement. The solution needs to be realistic, in line with your corporate culture, and deliver the right mix of technology, innovation and practicality, all with the appropriate cost-to-value ratio. Management must avoid the lure of overengineering to meet the goal, and thereby incurring more expense and complexity than needed. And the journey from perceived solution to actual solution to achieve a desired outcome might include some surprising elements.

For example, accomplishing the goal of reducing customer service costs by 30 percent might call for enhanced customer service representative (CSR) education and a reduction in the average number of calls a customer makes to the call center each year. The eventual solution may be very complex, and require touching all areas of the meter-to-cash process, along with implementing next generation technology. Or the solution may be as simple as upgrading the customer’s bill to provide more accurate and timely information. Putting more information in the customer’s hands makes billing easier to understand, resulting in fewer customer calls per year, leading to lower customer service costs. The value proposition enabling the business outcome might rely on a more robust analytics engine for analyzing and presenting data to customers. There are generally multiple paths that can bring about achieving a desired business outcome. Seeking external help on the pros and cons of the paths might be valuable to utility executives,
especially if the path involves deploying new technology.

Level 4: Measure Solution Results. Continuous process improvement must be a component of all solutions. The results must be measured and compared against the desired business outcomes. Reviewing results and lessons learned in a closed loop will empower continuous process improvement and maintain focus on the process.

Conservation and Education

While current technology may not be up to the task of helping consumers conserve and save money on energy, those restrictions will change in the very near future. Utilities need to start viewing themselves less as responders to supply and demand and more as advocates for conservation, the environment, and de-coupling of rates. Massive investments in clean and renewable energy, and smart grid technology, will empower customers to employ demand response decisions and gain energy efficiency. The real issue for the utility will not be how to implement the technology itself – wired, wireless, satellite, etc. – but how best to use the technology to achieve its desired business outcomes. Further, utilities need to be prepared for some disruption to business as usual while technology and business processes undergo a sea change.

The capability of deploying a smart grid and advanced meter management (AMM) is one of the most significant changes impacting utilities today. The outcomes are not achieved by technology alone. Those outcomes require the merging of AMM with meter-to-cash processes. The utility will realize business value only if the people and discrete processes within the customer care component of the end-toend process evolve to take advantage of new technology.

The New Reality

Most utilities already enjoy acceptable levels of customer satisfaction. As the smart grid comes on line, with its associated learning curve, myriad details and inevitable glitches, customers will depend on the utility for support and clarification. Call center volumes and average handle times will increase as the complexity of the product grows by an order of magnitude. The old standard of measuring productivity according to number of calls completed within a pre-determined number of minutes will no longer be viable. Average call length increased by a factor of four for one utility that has experimented with smart grid technology. Longer call times, however, can ultimately translate to increased customer satisfaction as consumers receive the information they need to understand the new system and how to reduce their energy bill.

But a four-fold increase in call center staff to accommodate longer calls is not economically practical. In the future, utilities will need to provide more in-depth education to CSRs so they can, in turn, educate customers. They may even need to change their hiring criteria, and seek more highly skilled call center staff who are already versed in the meter-to-cash process. For some customers, alternative sources of information such as the Internet will suffice, thus offsetting some of the strain placed on the call center.

Achieving Desired Outcomes

The following section provides examples of how the combination of advanced meter management and redefined meter-to-cash processes and tools can enable and help achieve desired business outcomes.

Accurate and Timely Data – With smart meters and the smart grid able to capture usage data in intervals as frequent as five minutes, utilities will have more current information about system activity than ever before. Developing a strategy for managing this massive database will require forethought to avoid overwhelming the back office. When fully deployed throughout a service area, customers will no longer receive estimated bills. Devices in the home will provide readouts about usage activity, and some consumer education may be needed to help households understand the presented data and how it translates to their usage patterns and billing. Demand response participation is likely to increase as consumers become more aware of the benefits of managing their energy usage patterns. The federal government’s stimulus bill funding may include allocations for retrofits for low-income homeowners. The call center can function as a resource for customers who wish to investigate this program.

Reduced Bad Debt – As noted earlier, average handle time will be a less significant metric as consumer interaction with the call center increases. The CSR will become a key element in the strategy to reduce bad debt. CSRs will be the conduit for consumer education and building rapport with the customer when resolving past-due bills. As an alternative, utilities may want to turn to Madison Avenue to help them design and roll out a customer information campaign.

Better Revenue Management – If customer education about the smart grid pays off, and consumers are using energy more judiciously, utilities will benefit. Without the pressure to make capital investments for new plants, there will be more opportunities for profit-taking and shareholder rewards. Utilities may instead be able to make profits on their energy efficiency and investments. New technologies will help utilities avoid spending the hundreds of billions of dollars that would otherwise be needed for base load. In addition, demand response participation on the part of residential consumers will better align commercial and industrial (C&I) energy pricing with residential pricing. C&I customers will see the quality and consistency of their power supply improve.

Increased Energy Efficiency – Utilities, whether municipal, public or private, will feel the social pressure to apply technologies in order to gain energy efficiency and encourage conservation. The future utility will become a leader, instead of a follower, in the campaign to improve the environment and use energy resources wisely. By using energy more strategically – that is, understanding the benefits of off-peak usage – consumers will help their utility reduce carbon emissions, which is the ultimate desired business outcome for all involved.

Increased Stakeholder Satisfaction – Stakeholders run the gamut from shareholders and public utility commissions to consumers, utility employees and executives. All of these groups will be pleased if the public uses energy more efficiently, leading to more revenue for the utility and lower costs to consumers. Showing focus on business outcomes is generally a huge plus that helps increase stakeholder satisfaction.

Lower Cost to Serve – Utilities must try to design a business model with flatter delivery costs. For example, if it costs the utility $30 to $40 per customer per year, staying within that existing range with more and longer customer calls will be a challenge. Some utilities may opt out of providing customer service with in-house staff and contract with a service provider. Recognizing that supplying and managing energy, not delivering customer care, is their core competency, a utility can often reduce the cost of customer care by partnering with an organization that is an expert in this business process. If this is the path a utility takes it is very important to find the provider that will enable the desired outcomes of your business; not all service providers are equal or focus on outcomes. We expect relationships with vendors within the industry will change, with utilities embracing more business partners than in the past.

Increased Service Levels – Public utility commissions (PUC) often review financial and service metrics when considering a rate case. Utilities may need to collaborate with PUCs to help them understand the dynamics of smart meters, along with temporary changes in customer satisfaction and service levels, when submitting innovative rate cases and programs. Once the initial disruptive period of new technology is completed, utilities will be able to increase service levels with greater responsiveness to customer needs. When the call center staff is fully educated about smart meters and demand response, they will be positioned to provide customers with more comprehensive service, thus reducing the number of incoming and outgoing calls.

Future Competition – The current and upcoming changes in the industry are so dramatic that utilities must first assess how consumers are accepting change. Reinventing the grid via the smart grid and its related products and services will create new opportunities and new business models with potential for increased revenue. The extent to which the future market is more competitive depends on the rate of acceptance by consumers and how skillfully utilities adopt new business models. It is our premise that utilities who desire the right business outcomes and focus on enabling them through process, people, and technological changes will be most able to excel in a more competitive environment.

References

  1. Galvin Electricity Initiative, sponsored by The Galvin Project, Inc., www.galvinpower.org
  2. Press Release, “EPA Finds Greenhouse Gases Pose Threat to Public Health, Welfare/Proposed Finding Comes in Response to 2007 Supreme Court Ruling,” April 17, 2009. http://yosemite.epa.gov
  3. McKinsey Global Institute, “Wasted Energy: How the US Can Reach its Energy Productivity Potential,” McKinsey
    & Company, June 2007.

The Role of Telecommunications Providers in the Smart Grid

Utilities are facing a host of critical issues over the next 10 years. One of the major approaches to dealing with these challenges is for utilities to become much more "intelligent" through the development of Intelligent Utility Enterprises (IUE) and Smart Grids (SG). The IUE/SG will require ubiquitous communications systems throughout utility service territories, especially as automated metering infrastructure (AMI) becomes a reality. Wireless systems, such as the widespread cellular system AT&T and other public carriers already have, will play a major role in enabling these systems.

These communications must be two-way, all the way from the utility to individual homes. The Smart Grid will be a subset of the intelligent utility, enabling utility executives to make wise decisions to deal with the pending issues. Public carriers are currently positioned to support and provide a wide range of communications technologies and services such as WiFi, satellite and cellular, which it is continuing to develop to meet current and future utility needs.

Supply and demand reaching critical concern

Utilities face some formidable mountains in the near future and they must climb these in the crosshairs of regulatory, legislative and public scrutiny. Included are such things as a looming, increasing shortage of electricity which may become more critical as global warming concerns begin to compromise the ability to build large generating plants, especially those fueled by coal.

Utilities also have to contend with the growing political strength of an environmental movement that opposes most forms of generation other than those designated as "green energy." Thus, utilities face a political/legislative/regulatory perfect storm, on the one hand reducing their ability to generate electricity by conventional methods and, on the other, requiring levels of reliability they increasingly are finding it impossible to meet.

The Intelligent Utility Enterprise and Smart Grid, with AMI as a subset of the Smart Grid, as potential, partial solutions

The primary solution proposed to date, which utilities can embrace on their own without waiting for regulatory/legislative/ political clarity, is to use technology like IUEs to become much more effective organizations and to substitute intelligence in lieu of manpower with SGs. The Smart Grid evolution also will enable the general public to take part in solving these problems through demand response. A subset of that evolution will be outage management to ensure that outages are anticipated and, except where required by supply shortages, minimized rapidly and effectively.

The IUE/SG, for the first time, will enable utility executives to see exactly what is happening on the grid in real time, so they can make the critical, day-to-day decisions in an environment of increasingly high prices and diminished supply for electricity.

Wireless To Play A Major Role In Required Ubiquitous Communications

Automating the self-operating, self-healing grid – artificial intelligence

The IUE/SG obviously will require enterprise-wide digital communications to enable the rapid transfer of data between one system and another, all the way from smart meters and other in-home gateways to the boardrooms where critical decisions will be made. Already utilities have embraced service-oriented architecture (SOA), as a means of linking everything together. SOA-enabled systems are easily linked over IP, which is capable of operating over traditional wire and fiber optic communications systems, which many utilities have in place, as well as existing cellular wireless systems. Wireless communications are becoming more helpful in linking disparate systems from the home, through the distribution systems, to substations, control rooms and beyond to the enterprise. The ubiquitous utility communications of the future will integrate a wide range of systems, some of them owned by the utilities and others leased and contracted by various carriers.

The Smart Grid is a subset of the entire utility enterprise and is linked to the boardroom by various increasingly intelligent systems throughout.

Utility leadership will need vital information about the operation of the grid all the way into the home, where distributed generation, net billing, demand response reduction of voltage or current will take place. This communications network must be in real time and must provide information to all of what traditionally were called "back office" systems, but which now must be capable of collating information never before received or considered.

The distribution grid itself will have to become much more automated, self-healing, and self-operating through artificial intelligence. Traditional SCADA (supervisory control and data acquisition) will have to become more capable, and the data it collects will have to be pushed further up into the utility enterprise and to departments that have not previously dealt with real-time data.

The communications infrastructure In the past utilities typically owned much of their communications systems. Most of these systems are aged, and converting them to modern digital systems is difficult and expensive.

Utilities are likely to embrace a wide range of new and existing communications technologies as they grapple with their supply/demand disconnect problem. One of these is IP/MPLS (Internet Protocol/Multi Protocol Label Switching), which already is proven in utility communications networks as well as other industries which require mission critical communications. MPLS is used to make communications more reliable and provide the prioritization to ensure the required latency for specific traffic.

One of the advantages offered by public carriers is that their networks have almost ubiquitous coverage of utility service territories, as well as built-in switching capabilities. They also have been built to communications standards that, while still evolving, help ensure important levels of security and interoperability.

"Cellular network providers are investing billions of dollars in their networks," points out Henry L. Jones II, chief technology officer at SmartSynch, an AMI vendor and author of the article entitled "Want six billion dollars to invest in your AMI network?"

"AT&T alone will be spending 16-17 billion dollars in 2009," Jones notes. "Those investments are spent efficiently in a highly competitive environment to deliver high-speed connectivity anywhere that people live and work. Of course, the primary intent of these funds is to support mobile users with web browsing and e-mail. Communicating with meters is a much simpler proposition, and one can rely on these consumer applications to provide real-world evidence that scalability to system-wide AMI will not be a problem."

Utilities deal in privileged communications with their customers, and their systems are vulnerable to terrorism. As a result, Congress, through the Federal Energy Regulatory Authority (FERC), designated NERC as the agency responsible for ensuring security of all utility facilities, including communications.

As an example of meeting security needs at a major utility, AT&T is providing redundant communications systems over a wireless WAN for a utility’s 950 substations, according to Andrew Hebert, AT&T Area Vice President, Industry Solutions Mobility Practice. This enables the utility to meet critical infrastructure protection standards and "harden" its SCADA and distribution automation systems by providing redundant communications pathways.

SCADA communication, distributed automation, and even devices providing artificial intelligence reporting are possible with today’s modern communications systems. Latency is important in terms of automatic fault reporting and switching. The communications network must provide the delivery-time performance to this support substation automation as identified in IEEE 1646. Some wireless systems now offer latencies in the 125ms range. Some of the newer systems are designed for no more than 50ms latency.

As AMI becomes more widespread, the utility- side control of millions of in-home and in-business devices will have to be controlled and managed. Meter readings must be collected and routed to meter data management systems. While it is possible to feed all this data directly to some central location, it is likely that this data avalanche will be routed through substations for aggregation and handling and transfer to corporate WANs. As the number of meter points grows – and the number readings taken per hour and the number of in-home control signals increases, bandwidth and latency factors will have to be considered carefully.

Public cellular carriers already have interoperability (e.g., you can call someone on a cell phone although they use a different carrier), and it is likely that there will be more standardization of communications systems going forward. A paradigm shift toward national and international communications interoperability already has occurred – for example, with the global GSM standard on which the AT&T network is based. A similar shift in the communications systems utilities use is necessary and likely to come about in the next few years. It no longer is practical for utilities to have to cobble together communications with varying standards for different portions of their service territory, or different functional purposes.

Measuring Smart Metering’s Progress

Smart or advanced electricity metering, using a fixed network communications path, has been with us since pioneering installations in the US Midwest in the mid-1980s. That’s 25 years ago, during which time we have seen incredible advancements in information and communication technologies.

Remember the technologies of 1985? The very first mobile phones were just being introduced. They weighed as much as a watermelon and cost nearly $9,000 in today’s dollars. SAP had just opened its first sales office outside of Germany, and Oracle had fewer than 450 employees. The typical personal computer had a 10 megabyte hard drive, and a dot-com Internet domain was just a concept.

We know how much these technologies have changed since then, how they have been embraced by the public, and (to some degree at least) where they are going in the future. This article looks at how smart metering technology has developed over the same period. What has been the catalyst for advancements? And, most important, what does that past tell us about the future of smart metering?

Peter Drucker once said that “trying to predict the future is like trying to drive down a country road at night with no lights while looking out the back window.”

Let’s take a brief look out the back window, before driving forward.

Past Developments

Developments in the parallel field of wireless communications, with its strong standards base, are readily delineated into clear technology generations. While we cannot as easily pinpoint definitive phases of smart metering technology, we can see some major transitions and discern patterns from the large deployments illustrated in Figure 1, and perhaps, even identify three broad smart metering “generations.”

The first generation is probably the clearest to delineate. The first 10 years of smart metering deployments (until about 2004) were all one-way wireless, limited two-way wireless, or very low-bandwidth power-line carrier communications (PLC) to the meter, concentrated in the U.S. The market at this time was dominated by Distribution Control Systems, Inc. (DCSI) and, what was then, CellNet Data Systems, Inc. Itron Fixed Network 2.0 and Hunt Technologies’ TS1 solution would also fit into this generation.

More than technology, the strongest characteristic of this first generation is the limited scope of business benefits considered. With the exception of Puget Sound Energy’s time-of-use pricing program, the business case for these early deployments was focused almost exclusively on reducing meter reading costs. Effectively, these early deployments reproduced the same business case as mobile automated meter reading (AMR).

By 2004, approximately 10 million of these smart meters had been installed in the U.S. (about 7 percent of the national total); however, whatever public perception of smart metering there was at the time was decidedly mixed. The deployments received scant media coverage, which focused almost solely on troubled time-of-use pricing programs, perhaps digressing briefly to cover smart metering vendor mergers and lawsuits. But generally smart meters, by any name, were unknown among the general population.

Today’s Second Generation

By the early 2000s, some utilities, notably PPL and PECO, both in Pennsylvania, were beginning to expand the use of their smart metering infrastructure beyond the simple meter-to-cash process. With incremental enhancements to application integration that were based on first generation technology, they were initiating projects to use smart metering to: transform outage identification and response; explore more frequent reading and more granular data; and improve theft detection.

These initiatives were the first to give shape to a new perspective on smart metering, but it was power company Enel’s dramatic deployment of 30 million smart meters across Italy that crystallized the second generation.

For four years leading to 2005, Enel fully deployed key technology advancements, such as universal and integrated remote disconnect and load limiting, that previously did not exist on any real scale. These changes enabled a dramatically broader scope of business benefits as this was the first fully deployed solution designed from the ground up to look well beyond reducing meter reading costs.

The impact of Enel’s deployment and subsequent marketing campaign on smart metering developments in other countries should not be underestimated, particularly among politicians and regulators outside the U.S. In European countries, particularly Italy, and regions such as Scandinavia, the same model (and in many cases the same technology) was deployed. Enel demonstrated to the rest of the world what could be done without any high-profile public backlash. It set a competitive benchmark that had policymakers in other countries questioning progress in their jurisdictions and challenging their own utilities to achieve the same.

North American Resurgence

As significant as Enel’s deployment was on the global development of smart metering, it is not the basis for today’s ongoing smart metering technology deployments now concentrated in North America.

More than the challenges of translating a European technology to North America, the business objectives and customer environments were different. As the Enel deployment came to an end, governments and regulators – particularly those in California and Ontario – were looking for smart metering technology to be the foundation for major energy conservation and peak-shifting programs. They expected the technology to support a broad range of pricing programs, provide on-demand reads within minutes, and gather hourly interval profile data from every meter.

Utilities responded. Pacific Gas & Electric (PG&E), with a total of 9 million electric and natural gas meters, kick-started the movement. Others, notably Southern California Edison (SCE), invested the time and effort to advance the technology, championing additions such as remote firmware upgrades and home area network support.

As a result, a near dormant North American smart metering market was revived in 2007. The standard functionality we see in most smart metering specifications today and the technology basis for most planned deployments in North America was established.

These technology changes also contributed to a shift in public awareness of smart meters. As smart metering was considered by more local utilities, and more widely associated with growing interest in energy conservation, media interest grew exponentially. Between 2004 and 2008, references to smart or advanced meters (carefully excluding smart parking meters) in the world’s major newspapers nearly doubled every year, to the point where the technology is now almost common knowledge in many countries.

The Coming Third Generation

In the 25 years since smart meters were first substantially deployed, the technology has progressed considerably. While progress has not been as rapid as advancements in consumer communications technologies, smart metering developments such as universal interval data collection, integrated remote disconnect and load limiting, remote firmware upgrades and links to a home network are substantial advancements.

All of these advancements have been driven by the combination of forward-thinking government policymakers, a supportive regulator and, perhaps most important, a large utility willing to invest the time and effort to understand and demand more from the vendor community.

With this understanding of the drivers, and based on the technology deployment plans, we can map out key future smart metering technology directions. We expect to see the next generation of smart metering exhibit two dominant differences from today’s technology. This includes increased standardization across the entire smart metering solution scope and changes to back-office systems architecture that enables the extended benefits of smart metering.

Increased Standardization

The transition to the next generation of smart metering will be known more for its changes to how a smart meter works, rather than what a smart meter does.

The direct functions of a smart meter appear to be largely set. We expect to see continued incremental advancements in data quality and read reliability; improved power quality measurement; and more universal deployment of a remote disconnect and load limiting.

But how a smart meter provides these functions will further change. We believe the smart meter will become a much more integrated part of two networks: one inside the home; the other along the electricity distribution network.

Generally, an expectation of standards for communication from the meter into a home area network is well accepted by the industry – although the actual standard to be applied is still in question. As this home area network develops, we expect a smart meter to increasingly become a member of this network, rather than the principal mechanism in creating one.

As other smart grid devices are deployed further down the low voltage distribution system, we expect utilities to demand that the meter conform to these network communications standards. In other words, utilities will continue to reject the idea that other types of smart grid devices – those with even greater control of the electrical network – be incorporated into a proprietary smart meter local area network.

It appears that most of this drive to standardization will not be led by utilities in North America. For one, technology decisions in North America are rapidly being completed (for this first round of replacements, at least). The recent Federal Regulatory Energy Commission (FERC) staff report, entitled “2008 Assessment of Demand Response and Advanced Metering” found that of the 145 million meters in the U.S., utilities have already contracted to replace nearly 52 million with smart meters over the next five to seven years.

IBM’s analysis indicated that larger utilities have declared plans to replace these meters even faster – approximately 33 million smart meters by 2013. The meter communications approach, and quite often the vendors chosen for these deployments, has typically already been selected, leaving little room to fundamentally change the underlying technological approach.

Outside of Worldwide Interoperability for Microwave Access (WiMAX) experiments by utilities such as American Electric Power (AEP) and those in Ontario, and shared services initiatives in Texas and Ontario, none of the remaining large North American utilities appear to have a compelling need to drive dramatic technology advancements, given rate and time pressures from regulators.

Conversely, a few very large European programs are poised to push the technology toward much greater standards adoption:

  • EDF in France has started a trial of 300,000 meters following standard PLC communications from the meter to the concentrator. The full deployment to all 35 million EDF meters is expected to follow.
  • The U.K. government recently announced a mandatory replacement of both electricity and natural gas meters for all 46 million customers between 2010 and 2020. The U.K.’s unique market structure with competitive retailers having responsibility for meter ownership and operation is driving interoperability standards beyond currently available technology.
  • With its PRIME initiative, the Spanish utility Iberdrola plans to develop a new PLC-based, open standard for smart metering. It is starting with a pilot project in 2009, leading to full deployment to more than 10 million residential customers.

The combination of these three smart metering projects alone will affect 91 million smart meters, equal to two thirds of the total U.S. market. This European focus is expected to grow now that the Iberdrola project has taken the first steps to be the basis for the European Commission’s Open Meter initiative, involving 19 partners from seven European countries.

Rethinking Utility System Architectures

Perhaps the greatest changes to future smart metering systems will have nothing to do with the meter itself.

To date, standard utility applications for customer care and billing, outage management, and work management have been largely unchanged by smart metering. In fact, to reduce risk and meet schedules, utilities have understandably shielded legacy systems from the changes needed to support a smart meter rollout or new tariffs. They have looked to specialized smart metering systems, particularly meter data management systems (MDMS), to bridge the gap between a new smart metering infrastructure and their legacy systems.

As a result, many of the potential benefits of a smart metering infrastructure have yet to be fully realized. For instance, billing systems still operate on cycles set by past meter reading routes. Most installed outage management applications are unable to take advantage of a direct near-real-time connection to nearly every end point.

As application vendors catch up, we expect the third generation of smart meters to be characterized by changes to the overall utility architectures and the applications that comprise them. As applications are enhanced, and enterprise architectures adapted to the smart grid, we expect to see significant architectural changes, such as:

  • Much of the message brokering functions from disparate head-end systems to utility applications in an MDMS will migrate to the utility’s service bus.
  • As smart meters increasingly become devices on a standards-based network, more general network management applications now widely deployed for telecommunications networks will supplement vendor head-end systems.
  • Complex estimating and editing functions will become less valuable as the technology in the field becomes more reliable.
  • Security of the system, from home network to the utility firewall, needs to meet the much higher standards associated with grid operations, rather than those arising from the current meter-as-the-cash-register perspective.
  • Add-on functionality provided by some niche vendors will migrate to larger utility systems as they evolve to a smart metering world. For instance, Web presentment of interval data to customers will move from dedicated sites to become a broad part of utilities’ online offerings.

Conclusions

Looking back at 25 years of smart metering technology development, we can see that while it has progressed, it has not developed at the pace of the consumer communications and computing technologies they rely upon – and for good reasons.

Utilities operate under a very different investment timeframe compared to consumer electronics; decisions made by utilities today need to stand for decades, rather than mere months. While consumer expectations of technology and service continue to grow with each generation, in the regulated electricity distribution industry, any customer demands are often filtered through a blurry political and regulatory lens.

Even with these constraints, smart metering technology has evolved rapidly, and will continue to change in the future. The next generation, with increased standardized integration with other networks and devices, as well as changes to back office systems, will certainly transform what we now call smart metering. So much so, that much sooner than 25 years from now, those looking back at today’s smart meters may very well see them as we now see those watermelon-sized cell phones of the 1980’s.

The Smart Grid Gets Real

Utilities around the world are facing a future that demands technology and service to better measure, manage and control distributed resources. Sensus has anticipated that future with real-world solutions that are already at work in millions of households today. As a leading provider of advanced metering and related communications technologies to utilities worldwide, Sensus has been aggressively pushing the boundaries of utility management. Our innovative communication systems enable utilities to intelligently utilize their resources with unprecedented efficiency.

FlexNet Smart Grid Solution

FlexNet is the electric utility industry’s most powerful AMI solution. It meets AMI requirements of today; ubiquity, redundancy, security and demand response, and is smart grid ready. FlexNet is simple; its lean architecture uses a powerful, industry-leading two Watts of radio power to transmit information that maximizes range and minimizes operational costs with low infrastructure requirements. FlexNet insures sustainability, protecting the utility infrastructure investment and uninterrupted delivery.

Every FlexNet endpoint is equipped with the ability to accept downloadable revised code; modulations, protocols, frequency of operation, even data rate can be fully upgraded as future requirements and features are developed. Sensus FlexNet further mitigates risk by using APA™ (All Paths Always) technology; this ultimate form of self-healing ensures critical messages are delivered without re-routing delay.

iCon Smart Meters

The iCon line of solid state smart meters integrates seamlessly with the FlexNet AMI solution. Communication vendors and metrology engineers nationwide consistently find that the advanced family of Sensus meters provides complete functionality, superior reliability, flexible integration capability, industry standards compatibility, and economical value. The modular mechanical, electrical, and software designs, in combination with the advanced sensing capability, predictably deliver the speed, accuracy, and reliability required to meet today’s electric utility needs. With an unsurpassed accuracy exceeding ANSI C12.20 (Class 0.2), the iCon Meter by Sensus is built with a backbone of reliability and precision.

Thinking Smart

For more than 30 years, Newton- Evans Research Company has been studying the initial development and the embryonic and emergent stages of what the world now collectively terms the smart, or intelligent, grid. In so doing, our team has examined the technology behind the smart grid, the adoption and utilization rates of this technology bundle and the related market segments for more than a dozen or so major components of today’s – and tomorrow’s – intelligent grid.

This white paper contains information on eight of these key components of the smart grid: control systems, smart grid applications, substation automation programs, substation IEDs and devices, advanced metering infrastructure (AMI) and automated meter-reading devices (AMR), protection and control, distribution network automation and telecommunications infrastructure.

Keep in mind that there is a lot more to the smart grid equation than simply installing advanced metering devices and systems. A large AMI program may not even be the correct starting point for hundreds of the world’s utilities. Perhaps it should be a near-term upgrade to control center operations or to electronic device integration of the key substations, or an initial effort to deploy feeder automation or even a complete production and control (P&C) migration to digital relaying technology.

There simply is not a straightforward roadmap to show utilities how to develop a smart grid that is truly in that utility’s unique best interests. Rather, each utility must endeavor to take a step back and evaluate, analyze and plan for its smart grid future based on its (and its various stakeholders’) mission, its role, its financial and human resource limitations and its current investment in modern grid infrastructure and automation systems and equipment.

There are multiple aspects of smart grid development, some of which involve administrative as well as operational components of an electric power utility, and include IT involvement as well as operations and engineering; administrative management of customer information systems (CIS) and geographic information systems (GIS) as well as control center and dispatching operation of distribution and outage management systems (DMS and OMS); substation automation as well as true field automation; third-party services as well as in-house commitment; and of course, smart metering at all levels.

Space Station

I have often compared the evolution of the smart grid to the iterative process of building the international space station: a long-term strategy, a flexible planning environment, responsive changes incorporated into the plan as technology develops and matures, properly phased. What function we might need is really that of a skilled smart grid architect to oversee the increasingly complex duties of an effective systems planning organization within the utility organization.

All of these soon-to-be-interrelated activities need to be viewed in light of the value they add to operational effectiveness and operating efficiencies as well as the effect of their involvement with one another. If the utility has not yet done so, it must strive to adopt a systems-wide approach to problem solving for any one grid-related investment strategy. Decisions made for one aspect of control and automation will have an impact on other components, based on the accumulated 40 years of utility operational insights gained in the digital age.

No utility can today afford to play whack-a-mole with its approach to the intelligent grid and related investments, isolating and solving one problem while inadvertently creating another larger or more costly problem elsewhere because of limited visibility and “quick fix” decision making.

As these smart grid building blocks are put into service, as they become integrated and are made accessible remotely, the overall smart grid necessarily becomes more complex, more communications-centric and more reliant on sensor-based field developments.

In some sense, it reminds one of building the space station. It takes time. The process is iterative. One component follows another, with planning on a system-wide basis. There are no quick solutions. Everything must be very systematically approached from the outset.

Buckets of Spending

We often tackle questions about the buckets of spending for smart grid implementations. This is the trigger for the supply side of the smart grid equation. Suppliers are capable of developing, and will make the required R&D investment in, any aspect of transmission and distribution network product development – if favorable market conditions exist or if market outlooks can be supported with field research. Hundreds of major electric power utilities from around the world have already contributed substantially to our ongoing studies of smart grid components.

In looking at the operational/engineering components of smart grid developments, centering on the physical grid itself (whether a transmission grid, a distribution grid or both), one must include what today comprises P&C, feeder and switch automation, control center-based systems, substation measurement and automation systems, and other significant distribution automation activities.

On the IT and administrative side of smart grid development, one has to include the upgrades that will definitely be required in the near- or mid-term, including CIS, GIS, OMS and wide area communications infrastructure required as the foundation for automatic metering. Based on our internal estimates and those of others, spending for grid automation is pegged for 2008 at or slightly above $1 billion nationwide and will approach $3.5 billion globally. When (if) we add in annual spending for CIS, GIS, meter data management and communications infrastructure developments, several additional billions of dollars become part of the overall smart grid pie.

In a new question included in the 2008 Newton-Evans survey of control center managers, these officials were asked to check the two most important components of near-term (2008-2010) work on the intelligent grid. A total of 136 North American utilities and nearly 100 international utilities provided their comments by indicating their two most important efforts during the planning horizon.

On a summary basis, AMI led in mentions from 48 percent of the group. EMS/ SCADA investments in upgrades, new applications, interfaces et al was next, mentioned by 42 percent of the group. Distribution automation was cited by 35 percent as well.

Spending Outlook

The financial environment and economic outlook do not bode well for many segments of the national and global economies. One question we have continuously been asked well into this year is whether the electric power industry will suffer the fate of other industries and significantly scale back planned spending on T&D automation because of possible revenue erosion given the slowdown and fallout from this year’s difficult industrial and commercial environments.

Let’s first take a summary look at each of the five major components of T&D automation because these all are part and parcel of the operations/engineering view of the smart grid of the future.

Control Systems Outlook: Driven by SCADA-like systems and including energy management systems and distribution management software, this segment of the market is hovering around the $500 million mark on a global scale – excluding the values of turn-key control center projects (engineering, procurement and construction (EPC) of new control center facilities and communications infrastructure). We see neither growth nor erosion in this market for the near-term, with some up-tick in spending for new applications software and better visualization tools to compensate for the “aging” of installed systems. While not a control center-based system, outage management is a closely aligned technology development, and will continue to take hold in the global market. Sales of OMS software and platforms are already approaching the $100 million mark led by the likes of Oracle Utilities, Intergraph and MilSoft.

Substation Automation and Integration Programs: The market for substation IEDs, for new communications implementations and for integration efforts has grown to nearly $500 million. Multiyear programs aimed at upgrading, integrating and automating the existing global base of about a quarter million or so transmission and primary distribution substations have been underway for some time. Some programs have been launched in 2008 that will continue into 2011. We see a continuation of the growth in spending for critical substation A&I programs, albeit 2009 will likely see the slowest rate of growth in several years (less than 3 percent) if the current economic malaise holds up through the year. Continuing emphasis will be on HV transmission substations as the first priority for upgrades and addition of more intelligent electronic devices.

AMI/AMR: This is the lynchpin for the smart grid in the eyes of many industry observers, utility officials and perhaps most importantly, regulators at the state and federal levels of the U.S., Canada, Australia and throughout Western Europe. With nearly 1.5 billion electricity meters installed around the world, and about 93 percent being electro-mechanical, interest in smart metering can also be found in dozens of other countries, including Indonesia, Russia, Honduras, Malaysia, Australia, and Thailand. Another form of smart meters, the prepayment meter, is taking hold in some of the developing nations of the world. The combined resources of Itron, coupled with its Actaris acquisition, make this U.S. firm the global share leader in sales and installations of AMI and AMR systems and meters.

Protection and Control: The global market for protective relays, the foundation for P&C has climbed well above $1.5 billion. Will 2009 see a drop in spending for protective relays? Not likely, as these devices continue to expand in capabilities, and undertake additional functions (sequence of event recording, fault recording and analysis, and even acting as a remote terminal unit). To the surprise of many, there is still a substantial amount (perhaps as much as $125 million) being spent annually for electro-mechanical relays nearly 20 years into the digital relay era. The North American leader in protective relay sales to utilities is SEL, while GE Multilin continues to hold a leading share in industrial markets.

Distribution Automation: Today, when we discuss distribution automation, the topic can encompass any and all aspects of a distribution network automation scheme, from the control center-based SCADA and distribution management system on out to the substation, where RTUs, PLCs, power meters, digital relays, bay controllers and a myriad of communicating devices now help operate, monitor and control power flow and measurement in the medium voltage ranges.

Nonetheless, it is beyond the substation fence, reaching further down into the primary and secondary network, where we find reclosers, capacitors, pole top RTUs, automated overhead switches, automated feeders, line reclosers and associated smart controls. These are the new smart devices that comprise the basic building blocks for distribution automation. The objective will be achieved with the ability to detect and isolate faults at the feeder level, and enable ever faster service restoration. With spending approaching $1 billion worldwide, DA implementations will continue to expand over the coming decade, nearing $2.6 billion in annual spending by 2018.

Summary

The T&D automation market and the smart grid market will not go away this year, nor will it shrink. When telecommunications infrastructure developments are included, about $5 billion will have been spent in 2008 for global T&D automation programs. When AMI programs are adding into the mix, the total exceeds $7 billion. T&D automation spending growth will likely be subdued, perhaps into 2010. However, the overall market for T&D automation is likely to be propped up to remain at or near current levels of spending for 2009 and into 2010, benefiting from the continued regulatory-driven momentum for AMI/ AMR, renewable portfolio standards and demand response initiatives. By 2011, we should once again see healthier capital expenditure budgets, prompting overall T&D automation spending to reach about $6 billion annually. Over the 2008-2018 periods, we anticipate more than $75 billion in cumulative smart grid expenditures.

Expenditure Outlook

Newton-Evans staff has examined the current outlook for smart grid-related expenditures and has made a serious attempt to avoid double counting potential revenues from all of the components of information systems spending and the emerging smart grid sector of utility investment.

While the enterprise-wide IT portions (blue and red segments) of Figure 1 include all major components of IT (hardware, software, services and staffing), the “pure” smart grid components tend to be primarily in hardware, in our view. Significant overlap with both administrative and operational IT supporting infrastructure is a vital component for all smart grid programs underway at this time.

Between “traditional IT” and the evolving smart grid components, nearly $25 billion will likely be spent this year by the world’s electric utilities. Nearly one-third of all 2009 information technology investments will be “smart grid” related.

By 2013, the total value of the various pie segments is expected to increase substantially, with “smart grid” spending possibly exceeding $12 billion. While this amount is generally understood to be conservative, and somewhat lower than smart grid spending totals forecasted by other firms, we will stand by our forecasts, based on 31 years of research history with electric power industry automation and IT topics.

Some industry sources may include the total value of T&D capital spending in their smart grid outlook.

But that portion of the market is already approaching $100 billion globally, and will likely top $120 billion by 2013. Much of that market would go on whether or not a smart grid is involved. Clearly, all new procurements of infrastructure equipment will be made with an eye to including as much smart content as is available from the manufacturers and integrators.

What we are limiting our definition to is edge investment, the components of the 21st century digital transport and delivery systems being added on or incorporated into the building blocks (power transformers lines, switchgear, etc.) of electric power transmission and delivery.

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.