Lighting the Way

Persistent climate change concerns, volatile energy prices and a growing awareness of technological advancement in energy are leading consumers across the globe to reconsider their role in the electric power value chain. Likewise, substantial increases in utility infrastructure investment are likely due to global demands for climate change mitigation; the need to support aging networks and generation plants; and proliferation of government stimulus plans for weakened economies.

For energy and utility companies, this presents an historic opportunity to encourage new, mutually beneficial behaviors and create business models to meet new consumer demands.

Our last report, "Plugging in the Consumer: Innovating Utility Business Models for the Future," explored the radically changing relationship between energy providers and consumers who took part in a survey conducted in late 2007. Even during the global economic downturn, progress has continued along the two dimensions shaping these changes: technology advancement and consumers’ desire for more control. Ultimately, this will result in movement of the basis of the industry to a participatory network – an interconnected environment characterized by a wide variety of grid and network technologies that enable shared responsibility and benefits. It will drive the creation of entirely new markets and products.

To continue our research about consumer expectations, we launched a followup survey in the fall of 2008. We surveyed over 5,000 customers from an expanded group of countries. This included the "core group" from our prior survey – the U.S., the U.K., Germany, the Netherlands, Australia and Japan – plus Canada, Denmark, Belgium, France, Ireland and New Zealand. Our survey findings strongly suggest the historical view of customers as "like-minded" is already outdated in most places.

Encouraging New Behaviors

In our surveys over the past two years, many consumers demonstrated at least one goal associated with asserting more control over their energy usage. The features of a participatory network appeal tremendously to them, because it would offer abundant service options and information to manage energy usage according to specific goals, such as cost reduction or environmental impact.

There is not much evidence that consumers think lower rates are coming. Over half see the cost increasing at roughly the same pace as usage. Forty percent see their bills increasing more rapidly than their usage (or not decreasing as much as any reduction in usage). Six percent think their bills will increase more slowly (or decrease more rapidly) than their usage. Overall, this year’s respondents have a slightly more pessimistic view of the next five years than those last year.

Cost remains the powerful motivator behind a desire for control over energy usage and a willingness to change behavior. Four in five consumers are willing to change the time-of-day in which they perform energy-consuming housework in exchange for cost savings of 50 percent or more. With the prevalent feeling that prices will move inexorably upward and awareness of smart meters growing, over 90 percent of respondents indicated that they would like a smart meter or other tools to manage their usage, with 55 percent to 60 percent of these respondents willing to pay a one-time or monthly fee for that capability.

Consumers’ emphasis on climate change and the availability of renewable energy programs in response to this demand for more carbon-neutral products remained about the same year to year. Across the core group countries, the percentage reporting that they did not have renewable power programs available dropped to 16 percent from 21 percent in the new survey (see Figure 1). Rather than changing their answers to the affirmative, however, most of the movement was to "don’t know" (up to 50 percent from 46 percent).

According to industry experts in some of the countries surveyed, the high level of "don’t know" responses, in part, reflects doubts in some countries about the veracity of green power claims. Still, if to a larger extent many customers truly cannot answer that question, this could indicate a valuable opportunity lost to ineffective communication with customers in countries with significant renewable resources and high participation levels.

In addition to environmental concerns, the global economic downturn of 2008 is clearly having severe impact on consumers. Across the core group countries, the number of consumers paying a premium for green products and services is down 20 percent to 30 percent (see Figure 2).

This change in spending patterns also seems to influence perceptions of green power options among consumers from core group countries that do not have (or are unsure if they have) green power options. The percentage of people who say they want green power options is down slightly, falling to 78 percent in 2008 from 85 percent in 2007. But, during that one-year period, the percentage of those willing to pay an additional 20 percent or more monthly dropped by nearly two-thirds, to just 6 percent from 16 percent.

The percentage of those who have green power options and actually buy them remained about the same, however. This is not surprising given contractual commitments, significantly higher prices for nonrenewable fuels in the past year (which eliminated some of the cost differential between standard and green power), and the overall commitment to the environment expected of "green" consumers.

Analyzing Consumers

In "Plugging in the Consumer," we described an emerging segmentation comprised of four consumer types: passive ratepayers (PR), frugal goal-seekers (FGs), energy epicures (EE) and energy stalwarts (ES) (see Figure 3). Our latest survey results reinforce these segments as likely outcomes of current trends. Two main attributes are associated with variances in consumers’ behavior profiles:

  • Personal Initiative. A consumer’s willingness to make decisions and take action based on specific goals such as cost control, reliability, convenience and climate change impact.
  • Disposable Income. A consumer’s financial wherewithal to support energy-related goals. In early adoption phases, only those with sufficient resources will be able to implement new technologies and buy more expensive products.

We also found that other demographic characteristics – such as age and country of residence – affect the speed of technology adoption, ability to leverage control "behind the meter," goals embedded in accepting more responsibility for energy choices, among others.

Consumer Profiles

PRs that embody a passive preference for the status quo remain the most prevalent of any of the four consumer archetypes. However, we see a remarkable transition in progress. In the past, these typically uninvolved, acquiescent customers comprised virtually 100 percent of the customer base. They represent just 31 percent of our 2008 survey respondents.

The number of more engaged and goal-oriented customers all along the income spectrum is approaching one-half of the total customer base. Frugal goal-seekers (FGs), about 22 percent of the survey population, have limited resources but strong will to change the way they use energy and manage its consumption. This group desires low-cost control of energy choices. Energy stalwarts (ES) have enough strength in both will and wallet to proactively take measures from making simple efficiency improvements to generating their own electricity. They have a clear willingness to invest in energy choices and represent about one in five consumers surveyed. Both of these groups will strongly influence the other half of consumers as they succeed in meeting their goals.

The remaining respondents (26 percent) are the EEs, who are curious but not committed. While they actually demonstrate more knowledge about their provider and options than any other group, they do not share the cost concerns or clear desire for information and control. This appears to be a matter of choice and not ignorance. While passive in some ways, this group is open to experimentation, particularly when the cost and lifestyle impact of a behavioral change are low.

Generational Change

In the short term, changes in customer needs will occur based on personal initiative and income. In the long run, even more radical changes may emerge as the millennial generation continues to move into adulthood and the energy customer base. By varying definitions, the first wave of these information-hungry, technology-savvy consumers is somewhere in our 25- to 34-year-old demographic grouping and fully encompasses the 18- to 24-year-old age group.

Precisely at this juncture, we see major changes in the survey results related to the ways consumers learn about companies and products, what they value and what they will pay for, as well as how they communicate with each other and the companies with which they do business. This, ultimately, may give way to new customer segments that will influence the shape of the industry in ways unimagined just a decade or two ago. To effectively determine the best strategy for a customer-focused transition to the participatory network of the future, every provider of energy or related services will need to construct an inventory of existing customer interactions with a wide variety of current and future service and product models.

In the following sections, we outline how specific consumer segments view the technology and business advances associated with key interactions.

Learning about Providers

Important messages from providers do not always reach consumers, as evidenced by consumers’ lack of awareness of available green power options (see Figure 1).

Additionally, only one in six consumers foresees a decrease in usage over the next five years, and only about a third say their provider can help them save energy despite strong efforts by the industry and governments to promote efficiency. In particular, provider messages are not reaching the youngest consumers. For example, those aged 18 to 34 are 40 percent more likely to not know if they have a choice in providers versus those 35 and older. The under-34 group also is twice as likely to not even know their provider’s name.

While all age groups will continue to rely heavily on their providers for information about energy (85 percent to 90 percent of respondents indicated this was a likely source), reliance on other sources differed starkly. Those over 55 are more than 10 times more likely to look to government for energy information than to social networks and other Web 2.0 content. Current trends also imply that those under 25 are becoming almost as likely to use the latter, rather than the former. To reach all generations, companies need to understand how different consumers tend to educate themselves about providers and their offerings with the wide variety of media available.

Controlling Costs

Not surprisingly, those aged 18 to 34 were most eager for the types of "self-service" and automated energy management that smart metering and smart grids will bring. What may be surprising, however, is that this age group – and particularly those under 25 – is the most willing to pay a stated premium for these services of approximately $100 U.S. as a one-time fee, or a monthly fee of $5 U.S. (see Figure 4).

Having a message sent to a mobile device when power is out at the consumer’s home also garnered significantly higher interest from the under-25 age group. About 30 percent were more likely than the other age groups to pay $1 per month for such a service. This finding may be related to the generally higher willingness we observed of younger age groups to subscribe to these programs, to their higher rate of ownership of mobile data devices and plans, or a combination of the two.

Investing in the Consumer

Substantial new increases in investment in utility infrastructure will come with a great deal of public, regulatory and shareholder scrutiny. All of these stakeholders will want to know how the public as a whole can benefit.

Energy and utility companies will need a strategy for aligning customer wants and needs with technology deployment roadmaps, beginning with rigorous customer segmentation and building an inventory of customer interactions. This must be followed by a program to analyze the interactions that are anticipated with each consumer segment and to assess whether existing capabilities are sufficient to leverage the new infrastructure in ways that support the new customer experience:

  • Identifying customer wants and needs specific to the interactions that will be most important to each particular segment;
  • Identifying the interactions that can be most effectively enhanced through participatory network deployment strategies;
  • Defining new or augmented business capabilities and regulatory models that must be developed to translate technological capabilities into customer benefits;
  • Determining which capabilities, if any, will be ceded to other providers for further development;
  • Integrating the development of specific new business capabilities into the participatory network deployment roadmap; and
  • Communicating these new capabilities clearly and effectively to all stakeholders.

The outcome of this process will lead to critical decisions about the customer-facing business capabilities on which the enterprise will focus.

Existing organizational strengths and new capabilities to be developed – one by one or in combinations – will form the basis for a broad menu of new products and services that the energy provider can offer. Each energy or service provider must be prepared to analyze its customer base to determine specific wants and needs before assessing how customers want to see new products and services emerge. After preferences are evaluated, they need to be applied to the customer interaction inventory in a way that identifies what should to be enhanced through technological improvements, regulatory change or improvements to communication channels.

This needs to be an ongoing process; customer assessment will not cease to be important once the participatory network is in place. The good news is that the data required to perform this continual assessment will be ubiquitous and arrive in real time from multiple sources of value-generating insights. But with this capability comes a challenge: finding new and powerful ways to collect, assimilate and evaluate this torrent of data in a way that will lead to inspiration for new programs and products that appeals to an expanding number of involved consumers.

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.

Modeling Distribution Demand Reduction

In the past, distribution demand reduction was a technique used only in emergency situations a few times a year – if that. It was an all-or-nothing capability that you turned on, and hoped for the best until the emergency was over. Few utilities could measure the effectiveness, let alone the potential of any solutions that were devised.

Now, demand reduction is evolving to better support the distribution network during typical peaking events, rather than just emergencies. However, in this mode, it is important not only to understand the solution’s effectiveness, but to be able to treat it like any other dispatchable load-shaping resource. Advanced modeling techniques and capabilities are allowing utilities to do just that. This paper outlines various methods and tools that allow utilities to model distribution demand reduction capabilities within set time periods, or even in near real time.

Electricity demand continues to outpace the ability to build new generation and apply the necessary infrastructure needed to meet the ever-growing, demand-side increases dictated by population growth and smart residences across the globe. In most parts of the world, electrical energy is one of the most important characteristics of a modern civilization. It helps produce our food, keeps us comfortable, and provides lighting, security, information and entertainment. In short, it is a part of almost every facet of life, and without electrical energy, the modern interconnected world as we know it would cease to exist.

Every country has one or more initiatives underway, or in planning, to deal with some aspect of generation and storage, delivery or consumption issues. Additionally, greenhouse gases (GHG) and carbon emissions need to be tightly controlled and monitored. This must be carefully balanced with expectations from financial markets that utilities deliver balanced and secure investment portfolios by demonstrating fiduciary responsibility to sustain revenue projections and measured growth.

The architects of today’s electric grid probably never envisioned the day when electric utility organizations would purposefully take measures to reduce the load on the network, deal with highly variable localized generation and reverse power flows, or anticipate a regulatory climate that impacts the decisions for these measures. They designed the electric transmission and distribution systems to be robust, flexible and resilient.

When first conceived, the electric grid was far from stable and resilient. It took growth, prudence and planning to continue the expansion of the electric distribution system. This grid was made up of a limited number of real power and reactive power devices that responded to occasional changes in power flow and demand. However, it was also designed in a world with far fewer people, with a virtually unlimited source of power, and without much concern or knowledge of the environmental effects that energy production and consumption entail.

To effectively mitigate these complex issues, a new type of electric utility business model must be considered. It must rapidly adapt to ever-changing demands in terms of generation, consumption, environmental and societal benefits. A grid made up of many intelligent and active devices that can manage consumption from both the consumer and utility side of the meter must be developed. This new business model will utilize demand management as a key element to the operation of the utility, while at the same time driving the consumer spending behavior.

To that end, a holistic model is needed that understands all aspects of the energy value chain across generation, delivery and consumption, and can optimize the solution in real time. While a unifying model may still be a number of years away, a lot can be gained today from modeling and visualizing the distribution network to gauge the effect that demand reduction can – and does – play in near real time. To that end, the following solutions are surely well considered.

Advanced Feeder Modeling

First, a utility needs to understand in more detail how its distribution network behaves. When distribution networks were conceived, they were designed primarily with sources (the head of the feeder and substation) and sinks (the consumers or load) spread out along the distribution network. Power flows were assumed to be one direction only, and the feeders were modeled for the largest peak level.

Voltage and volt-ampere reactive power (VAR) management were generally considered for loss optimization and not load reduction. There was never any thought given to limiting power to segments of the network or distributed storage or generation, all of which could dramatically affect the flow of the network, even causing reverse flows at times. Sensors to measure voltage and current were applied at the head of the feeder and at a few critical points (mostly in historical problem areas.)

Planning feeders at most utilities is an exercise performed when large changes are anticipated (i.e., a new subdivision or major customer) or on a periodic basis, usually every three to five years. Loads were traditionally well understood with predictable variability, so this type of approach worked reasonably well. The utility also was in control of all generation sources on the network (i.e., peakers), and when there was a need for demand reduction, it was controlled by the utility, usually only during critical periods.

Today’s feeders are much more complex, and are being significantly influenced by both generation and demand from entities outside the control of the utility. Even within the utility, various seemingly disparate groups will, at times, attempt to alter power flows along the network. The simple model of worst-case peaking on a feeder is not sufficient to understand the modern distribution network.

The following factors must be considered in the planning model:

  • Various demand-reduction techniques, when and where they are applied and the potential load they may affect;
  • Use of voltage reduction as a load-shedding technique, and where it will most likely yield significant results (i.e., resistive load);
  • Location, size and capacity of storage;
  • Location, size and type of renewable generation systems;
  • Use and location of plug-in electrical vehicles;
  • Standby generation that can be fed into the network;
  • Various social ecosystems and their characteristics to influence load; and
  • Location and types of sensors available.

Generally, feeders are modeled as a single unit with their power characteristic derived from the maximum peaking load and connected kilovolt-amperage (KVA) of downstream transformers. A more advanced model treats the feeder as a series of connected segments. The segment definitions can be arbitrary, but are generally chosen where the utility will want to understand and potentially control these segments differently than others. This may be influenced by voltage regulation, load curtailment, stability issues, distributed generation sources, storage, or other unique characteristics that differ from one segment to the next.

The following serves as an advanced means to model the electrical distribution feeder networks. It provides for segmentation and sensor placement in the absence of a complete network and historical usage model. The modeling combines traditional electrical engineering and power-flow modeling with tools such as CYME and non-traditional approaches using geospatial and statistical analysis.

The model builds upon information such as usage data, network diagrams, device characteristics and existing sensors. It then adds elements that could present a discrepancy with the known model such as social behavior, demand-side programs, and future grid operations based on both spatio-temporal and statistical modeling. Finally, suggestions can be made about sensors’ placement and characteristics to the network to support system monitoring once in place.

Generally, a utility would take a more simplistic view of the problem. It would start by directly applying statistical analysis and stochastic modeling across the grid to develop a generic methodology for selecting the number of sensors, and where to place them based on sensor accuracy, cost and risk-of-error introduction from basic modeling assumptions (load allocation, timing of peak demand, and other influences on error.) However, doing so would limit the utility, dealing only with the data it has in an environment that will be changing dramatically.

The recommended and preferred approach performs some analysis to determine what the potential error sources are, which source is material to the sensor question, and which could influence the system’s power flows. Next, an attempt can be made to geographically characterize where on the grid these influences are most significant. Then, a statistical approach can be applied to develop a model for setting the number, type and location of additional sensors. Lastly sensor density and placement can be addressed.

Feeder Modeling Technique

Feeder conditioning is important to minimize the losses, especially when the utility wants to moderate voltage levels as a load modification method. Without proper feeder conditioning and sufficient sensors to monitor the network, the utility is at risk of either violating regulatory voltage levels, or potentially limiting its ability to reduce the optimal load amount from the system during voltage reduction operations.

Traditionally, feeder modeling is a planning activity that is done at periodic (for example, yearly) intervals or during an expected change in usage. Tools such as CYME – CYMDIST provide feeder analysis using:

  • Balanced and unbalanced voltage drop analysis (radial, looped or meshed);
  • Optimal capacitor placement and sizing to minimize losses and/or improve voltage profile;
  • Load balancing to minimize losses;
  • Load allocation/estimation using customer consumption data (kWh), distribution transformer size (connected kVA), real consumption (kVA or kW) or the REA method. The algorithm treats multiple metering units as fixed demands; and large metered customers as fixed load;
  • Flexible load models for uniformly distributed loads and spot loads featuring independent load mix for each section of circuit;
  • Load growth studies for multiple years; and
  • Distributed generation.

However, in many cases, much of the information required to run an accurate model is not available. This is either because the data does not exist, the feeder usage paradigm may be changing, the sampling period does not represent a true usage of the network, the network usage may undergo significant changes, or other non-electrical characteristics.

This represents a bit of a chicken-or-egg problem. A utility needs to condition its feeders to change the operational paradigm, but it also needs operational information to make decisions on where and how to change the network. The solution is a combination of using existing known usage and network data, and combining it with other forms of modeling and approximation to build the best future network model possible.

Therefore, this exercise refines traditional modeling with three additional techniques: geospatial analysis; statistical modeling; and sensor selection and placement for accuracy.

If a distribution management system (DMS) will be deployed, or is being considered, its modeling capability may be used as an additional basis and refinement employing simulated and derived data from the above techniques. Lastly, if high accuracy is required and time allows, a limited number of feeder segments can be deployed and monitored to validate the various modeling theories prior to full deployment.

The overall goals for using this type of technique are:

  • Limit customer over or under voltage;
  • Maximize returned megawatts in the system in load reduction modes;
  • Optimize the effectiveness of the DMS and its models;
  • Minimize cost of additional sensors to only areas that will return the most value;
  • Develop automated operational scenarios, test and validation prior to system-wide implementation; and
  • Provide a foundation for additional network automation capabilities.

The first step starts by setting up a short period of time to thoroughly vet possible influences on the number, spacing and value offered by additional sensors on the distribution grid. This involves understanding and obtaining information that will most influence the model, and therefore, the use of sensors. Information could include historical load data, distribution network characteristics, transformer name plate loading, customer survey data, weather data and other related information.

The second step is the application of geospatial analysis to identify areas of the grid most likely to have influences driving a need for additional sensors. It is important to recognize that within this step is a need to correlate those influential geospatial parameters with load profiles of various residential and commercial customer types. This step represents an improvement over simply applying the same statistical analysis generically over the entirety of the grid, allowing for two or more “grades” of feeder segment characteristics for which different sensor standards would be developed.

The third step is the statistical analysis and stochastic modeling to develop recommended standards and methodology for determining sensor placement based on the characteristic segments developed from the geospatial assessment. Items set aside as not material for sensor placement serve as a necessary input to the coming “predictive model” exercise.

Lastly, a traditional electrical and accuracy- based analysis is used to model the exact number and placement of additional sensors to support the derived models and planned usage of the system for all scenarios depicted in the model – not just summertime peaking.

Conclusion

The modern distribution network built for the smart grid will need to undergo significantly more detailed planning and modeling than a traditional network. No one tool is suited to the task, and it will take multiple disciplines and techniques to derive the most benefit from the modeling exercise. However, if a utility embraces the techniques described within this paper, it will not only have a better understanding of how its networks perform in various smart grid scenarios, but it will be better positioned to fully optimize its networks for load and loss optimization.

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.

Silver Spring Networks

When engineers built the national electric grid, their achievement made every other innovation built on or run by electricity possible – from the car and airplane to the radio, television, computer and the Internet. Over decades, all of these inventions have gotten better, smarter and cheaper while the grid has remained exactly the same. As a result, our electrical grid is operating under tremendous stress. The Department of Energy estimates that by 2030, demand for power will outpace supply by 30 percent. And this increasing demand for low-cost, reliable power must be met alongside growing environmental concerns.

Silver Spring Networks (SSN) is the first proven technology to enable the smart grid. SSN is a complete smart grid solutions company that enables utilities to achieve operational efficiencies, reduce carbon emissions and offer their customers new ways to monitor and manage their energy consumption. SSN provides hardware, software and services that allow utilities to deploy and run unlimited advanced applications, including smart metering, demand response, distribution automation and distributed generation, over a single, unified network.

The smart grid should operate like the Internet for energy, without proprietary networks built around a single application or device. In the same way that one can plug any laptop or device into the Internet, regardless of its manufacturer, utilities should be able to “plug in” any application or consumer device to the smart grid. SSN’s Smart Energy Network is based on open, Internet Protocol (IP) standards, allowing for continuous, two-way communication between the utility and every device on the grid – now and in the future.

The IP networking standard adopted by Federal agencies has proven secure and reliable over decades of use in the information technology and finance industries. This network provides a high-bandwidth, low-latency and cost-effective solution for utility companies.

SSN’s Infrastructure Cards (NICs) are installed in “smart” devices, like smart meters at the consumer’s home, allowing them to communicate with SSN’s access points. Each access point communicates with networked devices over a radius of one or two miles, creating a wireless communication mesh that connects every device on the grid to one another and to the utility’s back office.

Using the Smart Energy Network, utilities will be able to remotely connect or disconnect service, send pricing information to customers who can understand how much their energy is costing in real time, and manage the integration of intermittent renewable energy sources like solar panels, plug-in electric vehicles and wind farms.

In addition to providing The Smart Energy Network and the software/firmware that makes it run smoothly, SSN develops applications like outage detection and restoration, and provides support services to their utility customers. By minimizing or eliminating interruptions, the self-healing grid could save industrial and residential consumers over $100 billion per year.

Founded in 2002 and headquartered in Redwood City, Ca., SSN is a privately held company backed by Foundation Capital, Kleiner Perkins Caufield & Byers and Northgate Capital. The company has over 200 employees and a global reach, with partnerships in Australia, the U.K. and Brazil.

SSN is the leading smart grid solutions provider, with successful deployments with utilities serving 20 percent of the U.S. population, including Florida Power & Light (FPL), Pacific Gas & Electric (PG&E), Oklahoma Gas & Electric (OG&E) and Pepco Holdings, Inc. (PHI), among others.

FPL is one of the largest electric utilities in the U.S., serving approximately 4.5 million customers across Florida. In 2007, SSN and FPL partnered to deploy SSN’s Smart Energy Network to 100,000 FPL customers. It began with rigorous environmental and reliability testing to ensure that SSN’s technology would hold up under the harsh environmental conditions in some areas of Florida. Few companies are able to sustain the scale and quality of testing that FPL required during this deployment, including power outage notification testing, exposure to water and salt spray and network throughput performance test for self-healing failover characteristics.

SSN’s solution has met or exceeded all FPL acceptance criteria. FPL plans to continue deployment of SSN’s Smart Energy Network at a rate of one million networked meters per year beginning in 2010 to all 4.5 million residential customers.

PG&E is currently rolling out SSN’s Smart Energy Network to all 5 million electric customers over a 700,000 square-mile service area.

OG&E, a utility serving 770,000 customers in Oklahoma and western Arkansas, worked with SSN to deploy a small-scale pilot project to test The Smart Energy Network and gauge customer satisfaction. The utility deployed SSN’s network, along with an energy management web-based portal in 25 homes in northwest Oklahoma City. Another 6,600 apartments were given networked meters to allow remote initiation and termination of service.

Consumer response to the project was overwhelmingly positive. Participating residents said they gained flexibility and control over their household’s energy consumption by monitoring their usage on in-home touch screen information panels. According to one customer, “It’s the three A’s: awareness, attitude and action. It increased our awareness. It changed our attitude about when we should be using electricity. It made us take action.”

Based on the results, OG&E presented a plan for expanded deployment to the Oklahoma Corporation Commission for their consideration.

PHI recently announced its partnership with SSN to deliver The Smart Energy Network to its 1.9 million customers across Washington, D.C., Delaware, Maryland and New Jersey. The first phase of the smart grid deployment will begin in Delaware in March 2009 and involve SSN’s advanced metering and distribution automation technology. Additional deployment will depend on regulatory authorization.

The impact of energy efficiency is enormous. More aggressive energy efficiency efforts could cut the growth rate of worldwide energy consumption by more than half over the next 15 years, according to the McKinsey Global Institute. The Brattle Group states that demand response could reduce peak load in the U.S. by at least 5 percent over the next few years, saving over $3 billion per year in electricity costs. The discounted present value of these savings would be $35 billion over the next 20 years in the U.S. alone, with significantly greater savings worldwide.

Governments throughout the EU, Canada and Australia are now mandating implementation of alternate energy and grid efficiency network programs. The Smart Energy Network is the technology platform that makes energy efficiency and the smart grid possible. And, it is working in the field today.

Managing Communications Change

Change is being forced upon the utilities industry. Business drivers range from stakeholder pressure for greater efficiency to the changing technologies involved in operational energy networks. New technologies such as intelligent networks or smart grids, distribution automation or smart metering are being considered.

The communications network is becoming the key enabler for the evolution of reliable energy supply. However, few utilities today have a communications network that is robust enough to handle and support the exacting demands that energy delivery is now making.

It is this process of change – including the renewal of the communications network – that is vital for each utility’s future. But for the utility, this is a technological step change requiring different strategies and designs. It also requires new skills, all of which have been implemented in timescales that do not sit comfortably with traditional technology strategies.

The problems facing today’s utility include understanding the new technologies and assessing their capabilities and applications. In addition, the utility has to develop an appropriate strategy to migrate legacy technologies and integrate them with the new infrastructure in a seamless, efficient, safe and reliable manner.

This paper highlights the benefits utilities can realize by adopting a new approach to their customers’ needs and engaging a network partner that will take responsibility for the network upgrade, its renewal and evolution, and the service transition.

The Move to Smart Grids

The intent of smart grids is to provide better efficiency in the production, transport and delivery of energy. This is realized in two ways:

  • Better real-time control: ability to remotely monitor and measure energy flows more closely, and then manage those flows and the assets carrying them in real time.
  • Better predictive management: ability to monitor the condition of the different elements of the network, predict failure and direct maintenance. The focus is on being proactive to real needs prior to a potential incident, rather than being reactive to incidents, or performing maintenance on a repetitive basis whether it is needed or not.

These mechanisms imply more measurement points, remote monitoring and management capabilities than exist today. And this requires a greater reliance on reliable, robust, highly available communications than has ever been the case before.

The communications network must continue to support operational services independently of external events, such as power outages or public service provider failure, yet be economical and simple to maintain. Unfortunately, the majority of today’s utility communications implementations fall far short of these stringent requirements.

Changing Environment

The design template for the majority of today’s energy infrastructure was developed in the 1950s and 1960s – and the same is true of the associated communications networks.

Typically, these communications networks have evolved into a series of overlays, often of different technology types and generations (see Figure 1). For example, protection tends to use its own dedicated network. The physical realization varies widely, from tones over copper via dedicated time division multiplexing (TDM) connections to dedicated fiber connections. These generally use a mix of privately owned and leased services.

Supervisory control and data acquisitions systems (SCADA) generally still use modem technology at speeds between 300 baud to 9.6k baud. Again, the infrastructure is often copper or TDM running as one of many separate overlay networks.

Lastly, operational voice services (as opposed to business voice services) are frequently analog on yet another separate network.

Historically, there were good operational reasons for these overlays. But changes in device technology (for example, the evolution toward e-SCADA based on IP protocols), as well as the decreasing support by communications equipment vendors of legacy communications technologies, means that the strategy for these networks has to be reassessed. In addition, the increasing demand for further operational applications (for example, condition monitoring, or CCTV, both to support substation automation) requires a more up-to-date networking approach.

Tomorrow’s Network

With the exception of protection services, communications between network devices and the network control centers are evolving toward IP-based networks (see Figure 2). The benefits of this simplified infrastructure are significant and can be measured in terms of asset utilization, reduced capital and operational costs, ease of operation, and the flexibility to adapt to new applications. Consequently, utilities will find themselves forced to seriously consider the shift to a modern, homogeneous communications infrastructure to support their critical operational services.

Organizing For Change

As noted above, there are many cogent reasons to transform utility communications to a modern, robust communications infrastructure in support of operational safety, reliability and efficiency. However, some significant considerations should be addressed to achieve this transformation:

Network Strategy. It is almost inevitable that a new infrastructure will cross traditional operational and departmental boundaries within the utility. Each operational department will have its own priorities and requirements for such a network, and traditionally, each wants some, or total, control. However, to achieve real benefits, a greater degree of centralized strategy and management is required.

Architecture and Design. The new network will require careful engineering to ensure that it meets the performance-critical requirements of energy operations. It must maintain or enhance the safety and reliability of the energy network, as well as support the traffic requirements of other departments.

Planning, Execution and Migration. Planning and implementation of the core infrastructure is just the start of the process. Each service requires its own migration plan and has its own migration priorities. Each element requires specialist technical knowledge, and for preference, practical field experience.

Operation. Gone are the days when a communications failure was rectified by sending an engineer into the field to find the fault and to fix it. Maintaining network availability and robustness calls for sound operational processes and excellent diagnostics before any engineer or technician hits the road. The same level of robust centralized management tools and processes that support the energy networks have to be put in place to support communications network – no matter what technologies are used in the field.

Support. Although these technologies are well understood by the telecommunications industry, they are likely to be new to the energy utilities industry. This means that a solid support organization familiar with these technologies must be implemented. The evolution process requires an intense level of up-front skills and resources. Often these are not readily available in-house – certainly not in the volume required to make any network renewal or transformation effective. Building up this skill and resource base by recruitment will not necessarily yield staff that is aware of the peculiarities of the energy utilities market. As a result, there will be significant time lag from concept to execution, and considerable risk for the utility as it ventures alone into unknown territory.

Keys To Successful Engagement

Engaging a services partner does not mean ceding control through a rigid contract. Rather, it means crafting a flexible relationship that takes into consideration three factors: What is the desired outcome of the activity? What is the best balance of scope between partner assistance and in-house performance to achieve that outcome? How do you retain the flexibility to accommodate change while retaining control?

Desired outcome is probably the most critical element and must be well understood at the outset. For one utility, the desired outcome may be to rapidly enable the upgrade of the complete energy infrastructure without having to incur the upfront investment in a mass recruitment of the required new communications skills.

For other utilities, the desired outcome may be different. But if the outcomes include elements of time pressure, new skills and resources, and/or network transformation, then engaging a services partner should be seriously considered as one of the strategic options.

Second, not all activities have to be in scope. The objective of the exercise might be to supplement existing in-house capabilities with external expertise. Or, it might be to launch the activity while building up appropriate in-house resources in a measured fashion through the Build-Operate- Transfer (BOT) approach.

In looking for a suitable partner, the utility seeks to leverage not only the partner’s existing skills, but also its experience and lessons learned performing the same services for other utilities. Having a few bruises is not a bad thing – this means that the partner understands what is at stake and the range of potential pitfalls it may encounter.

Lastly, retaining flexibility and control is a function of the contract between the two parties which should be addressed in their earliest discussions. The idea is to put in place the necessary management framework and a robust change control mechanism based on a discussion between equals from both organizations. The utility will then find that it not only retains full control of the project without having to take day-to-day responsibility for its management, but also that it can respond to change drivers from a variety of sources – such as technology advances, business drivers, regulators and stakeholders.

Realizing the Benefits

Outsourcing or partnering the communications transformation will yield benefits, both tangible and intangible. It must be remembered that there is no standard “one-size-fits-all” outsourcing product. Thus, the benefits accrued will depend on the details of the engagement.

There are distinct tangible benefits that can be realized, including:

Skills and Resources. A unique benefit of outsourcing is that it eliminates the need to recruit skills not available internally. These are provided by the partner on an as-needed basis. The additional advantage for the utility is that it does not have to bear the fixed costs once they are no longer required.

Offset Risks. Because the partner is responsible for delivery, the utility is able to mitigate risk. For example, traditionally vendors are not motivated to do anything other than deliver boxes on time. But with a well-structured partnership, there is an incentive to ensure that the strategy and design are optimized to economically deliver the required services and ease of operation. Through an appropriate regime of business-related key performance indicators (KPIs), there is a strong financial incentive for the partner to operate and upgrade the network to maintain peak performance – something that does not exist when an in-house organization is used.

Economies of Scale. Outsourcing can bring the economies of scale resulting from synergies together with other parts of the partner’s business, such as contracts and internal projects.

There also are many other benefits associated with outsourcing that are not as immediately obvious and commercially quantifiable as those listed above, but can be equally valuable.

Some of these less tangible benefits include:

Fresh Point of View. Within most companies, employees often have a vested interest in maintaining the status quo. But a managed services organization has a vested interest in delivering the best possible service to the customer – a paradigm shift in attitude that enables dramatic improvements in performance and creativity.

Drive to Achieve Optimum Efficiency. Executives, freed from the day-to-day business of running the network, can focus on their core activities, concentrating on service excellence rather than complex technology decisions. To quote one customer, “From my perspective, a large amount of my time that might have in the past been dedicated to networking issues is now focused on more strategic initiatives concerned with running my business more effectively.”

Processes and Technologies Optimization. Optimizing processes and technologies to improve contract performance is part of the managed services package and can yield substantial savings.

Synergies with Existing Activities Create Economies of Scale. A utility and a managed services vendor have considerable overlap in the functions performed within their communications engineering, operations and maintenance activities. For example, a multi-skilled field force can install and maintain communications equipment belonging to a variety of customers. This not only provides cost savings from synergies with the equivalent customer activity, but also an improved fault response due to the higher density of deployed staff.

Access to Global Best Practices. An outsourcing contract relieves a utility of the time-consuming and difficult responsibility of keeping up to speed with the latest thinking and developments in technology. Alcatel-Lucent, for example, invests around 14 percent of its annual revenue into research and development; its customers don’t have to.

What Can Be Outsourced?

There is no one outsourcing solution that fits all utilities. The final scope of any project will be entirely dependent on a utility’s specific vision and current circumstances.

The following list briefly describes some of the functions and activities that are good possibilities for outsourcing:

Communications Strategy Consulting. Before making technology choices, the energy utility needs to define the operational strategy of the communications network. Too often communications is viewed as “plug and play,” which is hardly ever the case. A well-thought-out communications strategy will deliver this kind of seamless operation. But without that initial strategy, the utility risks repeating past mistakes and acquiring an ad-hoc network that will rapidly become a legacy infrastructure, which will, in turn, need replacing.

Design. Outsourcing allows utilities to evolve their communications infrastructure without upfront investment in incremental resources and skills. It can delegate responsibility for defining network architecture and the associated network support systems. A utility may elect to leave all technological decisions to the vendor and merely review progress and outcomes. Or, it may retain responsibility for technology strategy, and turn to the managed services vendor to turn the strategy into architecture and manage the subsequent design and project activities.

Build. Detailed planning of the network, the rollout project and the delivery of turnkey implementations all fall within the scope of the outsourcing process.

Operate, Administer and Maintain. Includes network operations and field and support services:

  • Network Operations. A vendor such as Alcatel-Lucent has the necessary experience in operating Network Operations Centers (NOCs), both on a BOT and ongoing basis. This includes handling all associated tasks such as performance and fault monitoring, and services management.
  • Network and Customer Field Services. Today, few energy utilities consider outside maintenance and provisioning activities to be a strategic part of their business and recognize they are prime candidates for outsourcing. Activities that can be outsourced include corrective and preventive maintenance, network and service provisioning, and spare parts management, return and repair – in other words, all the daily, time-consuming, but vitally important elements for running a reliable network.
  • Network Support Services. Behind the first-line activities of the NOC are a set of engineering support functions that assist with more complex faults – these are functions that cannot be automated and tend to duplicate those of the vendor’s. The integration and sharing of these functions enabled by outsourcing can significantly improve the utility’s efficiency.

Conclusion

Outsourcing can deliver significant benefits to a utility, both in terms of its ability to invest in and improve its operation and associated costs. However, each utility has its own unique circumstances, specific immediate needs, and vision of where it is going. Therefore, each technical and operational solution is different.

Alcatel-Lucent Your Smart Grid Partner

Alcatel-Lucent offers comprehensive capabilities that combine Utility industry – specific knowledge and experience with carrier – grade communications technology and expertise. Our IP/MPLS Transformation capabilities and Utility market – specific knowledge are the foundation of turnkey solutions designed to enable Smart Grid and Smart Metering initiatives. In addition, Alcatel-Lucent has specifically developed Smart Grid and Smart Metering applications and solutions that:

  • Improve the availability, reliability and resiliency of critical voice and data communications even during outages
  • Enable optimal use of network and grid devices by setting priorities for communications traffic according to business requirements
  • Meet NERC CIP compliance and cybersecurity requirements
  • Improve the physical security and access control mechanism for substations, generation facilities and other critical sites
  • Offer a flexible and scalable network to grow with the demands and bandwidth requirements of new network service applications
  • Provide secure web access for customers to view account, electricity usage and billing information
  • Improve customer service and experience by integrating billing and account information with IP-based, multi-channel client service platforms
  • Reduce carbon emissions and increase efficiency by lowering communications infrastructure power consumption by as much as 58 percent

Working with Alcatel-Lucent enables Energy and Utility companies to realize the increased reliability and greater efficiency of next-generation communications technology, providing a platform for, and minimizing the risks associated with, moving to Smart Grid solutions. And Alcatel-Lucent helps Energy and Utility companies achieve compliance with regulatory requirements and reductions in operational expenses while maintaining the security, integrity and high availability of their power infrastructure and services. We build Smart Networks to support the Smart Grid.

American Recovery and Reinvestment Act of 2009 Support from Alcatel-Lucent

The American Recovery and Reinvestment Act (ARRA) of 2009 was adopted by Congress in February 2009 and allocates $4.5 billion to the Department of Energy (DoE) for Smart Grid deployment initiatives. As a result of the ARRA, the DoE has established a process for awarding the $4.5 billion via investment grants for Smart Grid Research and Development, and Deployment projects. Alcatel-Lucent is uniquely qualified to help utilities take advantage of the ARRA Smart Grid funding. In addition to world-class technology and Smart Grid and Smart Metering solutions, Alcatel-Lucent offers turnkey assistance in the preparation of grant applications, and subsequent follow-up and advocacy with federal agencies. Partnership with Alcatel-Lucent on ARRA includes:

  • Design Implementation and support for a Smart Grid Network
  • Identification of all standardized and unique elements of each grant program
  • Preparation and Compilation of all required grant application components, such as project narratives, budget formation, market surveys, mapping, and all other documentation required for completion
  • Advocacy at federal, state, and local government levels to firmly establish the value proposition of a proposal and advance it through the entire process to ensure the maximum opportunity for success

Alcatel-Lucent is a Recognized Leader in the Energy and Utilities Market

Alcatel-Lucent is an active and involved leader in the Energy and Utility market, with active membership and leadership roles in key Utility industry associations, including the Utility Telecom Council (UTC), the American Public Power Association (APPA), and Gridwise. Gridwise is an association of Utilities, industry research organizations (e.g., EPRI, Pacific Northwest National Labs, etc.), and Utility vendors, working in cooperation with DOE to promote Smart Grid policy, regulatory issues, and technologies (see www.gridwise.org for more info). Alcatel-Lucent is also represented on the Board of Directors for UTC’s Smart Network Council, which was established in 2008 to promote and develop Smart Grid policies, guidelines, and recommended technologies and strategies for Smart Grid solution implementation.

Alcatel-Lucent IP MPLS Solution for the Next Generation Utility Network

Utility companies are experienced at building and operating reliable and effective networks to ensure the delivery of essential information and maintain flawless service delivery. The Alcatel-Lucent IP/MPLS solution can enable the utility operator to extend and enhance its network with new technologies like IP, Ethernet and MPLS. These new technologies will enable the utility to optimize its network to reduce both CAPEX and OPEX without jeopardizing reliability. Advanced technologies also allow the introduction of new Smart Grid applications that can improve operational and workflow efficiency within the utility. Alcatel-Lucent leverages cutting edge technologies along with the company’s broad and deep experience in the utility industry to help utility operators build better, next-generation networks with IP/MPLS.

Alcatel-Lucent has years of experience in the development of IP, MPLS and Ethernet technologies. The Alcatel-Lucent IP/MPLS solution offers utility operators the flexibility, scale and feature sets required for mission-critical operation. With the broadest portfolio of products and services in the telecommunications industry, Alcatel-Lucent has the unparalleled ability to design and deliver end-to-end solutions that drive next-generation utility networks.

About Alcatel-Lucent

Alcatel-Lucent’s vision is to enrich people’s lives by transforming the way the world communicates. As a leader in utility, enterprise and carrier IP technologies, fixed, mobile and converged broadband access, applications, and services, Alcatel-Lucent offers the end-to-end solutions that enable compelling communications services for people at work, at home and on the move.

With 77,000 employees and operations in more than 130 countries, Alcatel-Lucent is a local partner with global reach. The company has the most experienced global services team in the industry, and Bell Labs, one of the largest research, technology and innovation organizations focused on communications. Alcatel-Lucent achieved adjusted revenues of €17.8 billion in 2007, and is incorporated in France, with executive offices located in Paris.

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.

PHEVs Are on a Roll

The electric vehicle first made its appearance about a century ago, but it is only in recent years – months, to be more precise – that it has achieved breakthrough status as, quite possibly, the single-most important technological development having a positive impact on society today.

Climate change, over-dependence on fossil fuels, and the current economic crisis have combined to impact the automobile sector to a degree unforeseen, forcing technological innovation to direct its urgent attention toward the development of electric vehicles as an alternative means of transport, and a substitute for internal combustion engines. Many countries are supporting the approach in their political, energy and industrial planning directed toward the introduction of this type of vehicle. For example, the U.S. has a target of 1 million Plug-in Hybrid Electric Vehicles (PHEV) in operation by 2015. Spain expects to achieve the same number by 2014.

It is certainly true that there exist pressures capable of driving the introduction of the PHEV forward, but technological advances are the factors that underpin and give coherence to its development. There are several progressive improvements being made in technology, materials, and power generation and supply, which will support the deployment and use of electric vehicles in the coming years. They include: advances in battery manufacture and electronics (particularly in terms of power); the development of new communication protocols; ever more efficient and flexible information technologies; the growth of renewable energy sources in the electrical energy generation mix; and the concept of smart grids focused on more efficient electricity distribution. All of these improvements are underscored by a much greater degree of passion and personal involvement by the end-user.

Stakeholders and Utilities

With technology as the underlying catalyst, the scenario for electric vehicle use will include the impact and involvement of various stakeholders. This consists of: society itself, government and municipal entities, regulators, universities and research institutions, vehicle manufacturers, the ancillary automobile industry and its technological partners, battery manufacturers, the manufacturers of components, electrical and electronics systems, infrastructure suppliers, companies dedicated to mediation, billing and payment methods, ICT (Information and Communication Technology) companies, and of course, utilities.

If the electric vehicle is to become a genuinely alternative means of transportation, then this will depend on the involvement of, and interrelationship between, the above groups. One example of this is the formalizing of various agreements between certain stakeholders at both the national and international level (for example, Saab, Volvo, Wattenfall and ETC Battery in Sweden; Renault, PSA Peugeot Citroën, Toyota and EDF in France; and Iberdrola and General Motors at a global level) and the establishment of consortiums such as EDISON (Electric Vehicles in a Distributed and Integrated Market using Sustainable Energy and Open Networks) in Denmark.

If there is one dimension, however, which will be impacted most throughout the whole of the value chain, it is the electrical one. From power generation to retail, the introduction of this vehicle will require changes in current business models, and foreseeably, in utilities operational models. The short-term aim is to provide electrical energy for use in these vehicles in a more reliable and efficient way.

Battery Charging Impact

Given that charging could be the action having the greatest impact on the electrical sector, there are various alternatives for affecting this. These include:

  • Substitution. This involves a rapid exchange of vehicles and/or batteries, and the subsequent charging of both in an offline mode. It would require sharing of cars (vehicle usage and substitution) and battery charging stations for quick and automated battery exchange.
  • Direct Charging. This includes regular charging points situated in car parks, shopping centers and residences, and providing battery recharge while the vehicle is parked. There also need to be fast-charging points that could quickly charge a battery in 10 to 15 minutes.

To examine the advantages and disadvantages of the above methods, it helps to note the various pilot projects and research programs underway at both the conceptual and demonstration stages. These indicate the possibility of a coexistence scenario. Offline charging could be the least invasive method given the current system of fuel distribution. A network of “electricity stations” (as opposed to petrol stations) could provide a dedicated system of energy generation in a given location. As for direct charging, given the itinerant nature of user demand and his or her expected freedom to choose a particular charging method or location, this introduces an element of greater uncertainty, and impact on the electricity grid, requiring a system that better adapts to the lifestyle of the user.

Direct Charging and Its Impact on the Electricity Grid

Direct charging depends on various factors – notably battery characteristics (directly related to vehicle performance) and the range of time spans chosen to carry out the recharge. Associated with these are other variables: charging voltage, mode (DC, single-phase AC, and three-phase AC) and the characteristics of the charging systems employed: technology, components and their location, connectors, insulation, and the power and control electronics. All of these variables will influence the charging times, and will vary according to the power input (more power, less time) as shown in Figure 1. Therefore, depending on the kind of recharging, there will be an impact not only on the characteristics of the individual charging points but also on the supporting system.

Using extended range electrical vehicles (EREV) such as the Chevrolet Volt or Opel/Vauxhall Ampera as an example, it is estimated that annual home energy consumption from vehicle charging could be around 20 percent of the total, although some studies suggest this amount may be twice as much, based on the customer profile.

Based on the charging power input – and this is, of course, related to the methodology employed – it would be possible to fully recharge an EREV battery in about three hours. A fully charged battery would enable operation solely on electrical power for approximately 40 miles, a distance representing about 80 percent of daily car journeys based on the current averages. For a scenario like this it would be possible to use a charging method of about 4 kilowatt/220 volts.

If we analyze the impact in terms of energy supply and power capacity, there appears to be no medium-term problems in supporting these chargings, according to the data above. This is, however, a matter which depends on each individual country and also on the power transmission interconnections between them. In terms of the instantaneous power available, the charging method will have a greater or lesser impact, particularly on the distribution assets, depending on how it is carried out. Figure 2 shows how the power varies according to the charging method and the time of day when it is in use, taking into account the daily energy demand curve. We can, therefore, identify different scenarios from the most favourable (slow charging at off-peak times) to the most unfavourable (fast charging at peak times). With the latter we may find ourselves with distribution assets (e.g., transformers) incapable of supporting the heavy load of instant energy consumption.

It is necessary to link electric vehicle charging to the daily energy demand curve and instantaneous power availability in such a way that charging impacts the system as little as possible and maximizes the available energy resources. Ideally, there would be a move toward slow charging during off-peak periods. Furthermore, this kind of charging would not impact users as 90 percent of vehicles are not used between 11 a.m. and 6 p.m. Operating under such conditions would also permit the use of excess wind-generated power during off-peak times, enabling a clean locomotion device such as the PHEV to also use renewable (clean) energy as its primary source.

This all sounds reasonable, but the itinerant nature of roaming vehicle demand, together with relatively limited battery life, means that other variables such as home charging versus remote charging with the ability to measure consumption and set tariffs must be taken into account. What will be the charging price? How will charging be carried out when the vehicle is not parked at home, nor at its usual charging centre? What method will be used for making payments? Who will be involved in developing all this infrastructure and how will it all interrelate?

Smart Charging

One system providing answers to these questions is smart charging. Based on the concept, purpose and architecture of the smart grid, such technology can optimise charging in the most favorable way by considering several parameters. These may include: the current state of the electrical system; the battery charging level; tariff modes and associated demand-response models which may be applied (such as time of use, or TOU, tariffs); and the ability to use energy distributed and stored locally through an energy management system.

Smart charging would be capable of deciding when to charge in relation to different variables (for example, price and energy availability), and which energy sources to use (in-home energy storage, local and decoupled energy supply, plug-in to the distribution grid, etc.) Supporting the vehicle-to-grid (V2G) paradigm would enable managing and deciding not only when and how to best charge the vehicle, but also when to store energy in the vehicle battery that can later be returned to the grid for use in a local mode as a distributed energy source.

For all of this to be effective, a power and control electronics system (in both local and global mode), supported by information systems to manage those issues, is required. This will enable the optimal charging process (avoiding peak times, and doing fast charging only when necessary) and an intelligent measuring and tariff system. The latter may be either managed by utilities through advanced meter management (AMM), or virtually through energy tariffs and physical economic transactions. Such systems should allow for the interaction of various agents: end users, utilities, energy service companies (ESCO), infrastructure providers, banks and other method-of-payment companies.

Conclusion

Although there are still many unresolved issues around the introduction of electric vehicles (for example, incentives, carbon caps, tax collection, readiness of systems and business processes), the challenge associated with this means of locomotion and its effect on current business systems and models is a fascinating one. From an electrical viewpoint, there would not appear to be any significant impact on energy management in the medium term, but perhaps more so in terms of power requirements. As an example, some regions have adjusted to the massive introduction of air conditioning systems over recent years. While we are reassured as to the viability of electric vehicles, we are also alert to the possible significant impact of widespread vehicle charging, above all when considering a fast charging scenario.

The special characteristics of battery charging and its itinerant nature, the predicted volumes of power outlet and energy, the current state of tariff systems, the available technology, and the vision and state of deployment of smart grids and AMM, all add up to suggest a smart charging type of system would be the best option – though certainly complex to implement. Given the prominent role that information and communication technologies will play in such a system, it will be necessary to achieve consensus among various stakeholders over methodologies to be used, standards development, and in establishing a regulatory framework capable of supporting all the mechanisms and systems to be introduced.

We have already made good progress, and the electric vehicle could become an example that drives change in other business and technology models. It may well stimulate more rapid development of smart grids, encourage the creation of more efficient energy services and technologies, and lead to greater development and use of renewable energy sources, including a generation and distribution scenario based on the V2G paradigm.

It also may open the door to new businesses and stakeholders as well (such as the ESCOs) to introduce more dynamic, interactive demand response programs and broaden the function of battery storage as a provider of spinning reserves and ancillary services. These are all aspects for which it is now necessary to establish a basis for implementation and a short-term viability plan that will allow for the use of this technology with the aim of reaping its recognized benefits. Are we ready to step up to the challenge?