“When the intelligent grid gets built, will anyone notice?”
Don Von Dollen, EPRI’s IntelliGrid program manager, is only partly joking when he asks this question. Of course utilities will notice the benefits that come from greater intelligence in the power-distribution network—better diagnostics, greater reliability, more efficient use of assets, improved customer service, and greater control over load patterns.
At the same time, however, these advancements generally are occurring in small steps rather than giant leaps. Very few utilities will flip a switch and wake up the intelligent grid, like a mundane version of HAL from 2001: A Space Odyssey. That’s because grid intelligence does not emerge from a single rollout of revolutionary technology, but from strategic planning and targeted investments—a substation here, a metering project there—all aimed at a long-term vision.
“The book value of U.S. T&D assets is something like $400 billion,” Von Dollen observes. “That huge investment will not be transformed, but will evolve through incremental investments that knit together this new intelligent infrastructure, with communications networks and embedded processing.”
And there’s the rub for the intelligent grid.
Historically, U.S. utilities have tended to focus their business strategies on large capital investments, such as power plants and high-voltage transmission lines. And those investments have prioritized mature technologies with well-proven benefits—because that’s what regulators and investors demand of investor-owned utilities, particularly in the back-to-basics era.
The smart grid, however, is somewhat trickier to define, and offers different benefits for utilities depending on their operational systems, market structures, and load profiles. It never has been implemented on a large scale by any utility in North America, so it can hardly be called a mature technology—even though most of the hardware behind it is relatively well proven. Building the intelligent grid will require less technical innovation than it does strategic innovation—a characteristic not typically ascribed to U.S.-regulated utilities.
“To try something as revolutionary as the smart grid, the utility culture needs to change from one that is risk averse to one that accepts cutting-edge technology and focuses on innovation,” says Michael Lamb, executive director of Xcel Energy’s Utility Innovations project in Minneapolis. “It is very important to change the utility culture.”
By necessity if not by choice, that change already has begun.
Recent policy developments are forcing a cultural shift at many utilities. The Energy Policy Act of 2005 and other policy trends are driving the industry to focus on improving reliability, increasing efficiency, and giving customers more control over their energy consumption. With these drivers, the journey toward grid intelligence seems less like a futuristic sci-fi odyssey, and more like the prudent next step for the U.S. utility industry.
Not all utilities will take that step in exactly the same way, but as the experiences of Southern California Edison, CenterPoint Energy, and Xcel Energy attest, they all lead toward a brighter future for the U.S. electric power system.
“Smart utilities build smart grids,” Von Dollen says. “Intelligence comes from the way you make investments.”
While most states are approaching smart-grid projects with baby steps, California is shoving its investor-owned utilities into the future.
After studying the causes of the energy crisis that paralyzed the state in 2000 and 2001, the California Public Utilities Commission (CPUC) in 2004 instructed California’s investor-owned utilities to develop business cases for equipping their networks with advanced metering infrastructure (AMI)—largely to create a more robust platform to manage power loads and encourage conservation. That initiative now is bearing tangible results, with specific plans moving forward at Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric.
Most recently, in December 2006, Southern California Edison (SCE) issued formal requests for proposals (RFP) soliciting bids from smart-metering vendors to supply 5 million meters, a wireless two-way communication network, and a meter data management (MDM) system. When installed, the AMI network will allow hourly meter reads and a host of other advanced features, including remote connect and disconnect; long-term, remote upgrade capabilities; and open standards to accommodate smart devices, such as appliances and thermostats that will be required by the California Building Commission beginning in 2009.
The RFPs set forth an accelerated process for implementation, with bids due in January and February 2007, field testing in summer 2007, and full-scale deployment between 2009 and 2012. But while SCE’s plans are moving quickly, the company reached this point only after exhaustive deliberation. In fact, its initial AMI business case produced a discouraging prognosis: The available technology was too limited and too expensive to deliver cost-effective benefits, resulting in a $500 million net deficit.
“We had started from a traditional AMR [automated meter reading] perspective, but then we realized we had to look at it quite differently,” says Paul De Martini, SCE’s AMI program manager. “It became clear it wasn’t just about metering, but the opportunity to extend the central nervous system of the network out to the fingertips; to connect more of the dots that will create the intelligent grid.”
SCE worked with vendors and consultants to develop technologies that would allow the utility to extract more smart-grid functionality from its AMI investment. “The meter is important, but the way we leverage the system as a whole will bring service efficiencies and benefits to customers,” De Martini says.
For example, if meters could measure voltage at the end-user level, they would provide a wealth of data about network operations. With this information, SCE engineers could improve the performance of the distribution system by conducting more accurate predictive maintenance, leading to higher grid reliability, shorter service-response times, and more cost-effective deployment of hardware investments.
The prospect of such benefits pushed SCE’s AMI business case into the black, and energized the company to approach its AMI project from a more holistic perspective, involving not just the metering and customer-service operations, but every area that touches the distribution network.
“The more we looked at it, the more we got excited about the possibilities,” says James Kelly, SCE’s vice president of engineering and technical services. “The vision is an end-to-end process, integrating AMI with distribution automation, substation control, and bulk-transmission control.”
In addition to improving system reliability and efficiency, such capabilities also will allow the utility to provide a host of new services—not just time-of-use (TOU) pricing, but third-party applications that will help customers use electricity infrastructure and resources more efficiently. And such capabilities might allow California utilities to avert the kinds of crises that plagued their systems in 2000 and 2001—in ways that couldn’t happen without a smart grid.
“One can imagine a future in which California has a couple million plug-in hybrid vehicles,” Kelly says. “On a hot day the grid will draw upon those vehicles as distributed power sources. That’s the kind of exciting path that emerges if the grid becomes smarter” (see “New Load or New Resource?” December 2006).
California is not the only hotbed for intelligent-grid development in America. At least two large utilities in Texas—TXU and CenterPoint Energy-Houston—are moving forward with smart-grid projects using broadband-over-power line (BPL) communications technology.
The prospects for BPL got a boost in Texas in late 2005, when legislators enacted language in a cable-TV-related bill (S.B. 5) that cleared the way for utilities to use power lines for communications without running into onerous regulations or costs. A few months later, CenterPoint Energy-Houston announced its plan for a large-scale BPL demonstration in three neighborhoods, as part of a smart-grid strategy for its power system in the city.
CenterPoint teamed up with IBM Global Business Services to develop a hub-and-spoke architecture that uses substations as hubs, with BPL connections radiating out along medium-voltage distribution lines and connecting with Itron OpenWave meters. High-capacity broadband connections—using fiber optics, microwave, or other technology—will connect the substation hubs to a central MDM system.
Unlike a previous CenterPoint project that provided broadband Internet services to consumers, the CenterPoint project is planned strictly for communicating metering and distribution-network data.
“Just making the intelligent grid happen is a big enough challenge,” says Don Cortez, vice president of regulated operations support with CenterPoint Energy-Houston. “Selling broadband to consumers would make it a no-go business schedule.”
When CenterPoint removed the technical and business complexities of creating a new retail broadband service, BPL became an attractive platform for the intelligent grid. BPL is uniquely suited to smart-grid applications, because power lines already connect every device on the network. Additionally, BPL technology provides ample bandwidth—3 to 5 MB per second in CenterPoint’s case—to carry the massive quantities of data the intelligent grid will require.
“One of the major components of the intelligent grid is the communications layer,” Cortez says. “If you don’t have a robust communications layer, you probably can’t make the intelligent grid work very effectively.”
One reason is latency; without broadband connectivity, an intelligent grid must economize bandwidth, and that reduces its real-time functionality. “What really can make the market more efficient is the ability to exercise commands and get feedback immediately, not just for pricing but other things in the system, like air conditioning and appliance control,” Cortez says.
Additionally, by effectively creating a mesh of real-time monitoring devices throughout the grid, the system will give CenterPoint orders of magnitude more data about network operations. Such data would allow advanced diagnostic analysis and automatic outage detection and localization.
But this quantity of data requires much more sophisticated processing capabilities than have been necessary in the past, as well as the ability to integrate and analyze data coming from a potentially unprecedented number of different systems and devices.
“It’s not just the meter, but also the transformer, the substation, and the transmission grid,” says Michael Valocchi, global energy and utilities industry leader for IBM Global Business Services. “If we are going to have an intelligent grid, we need data from all those individual components.” IBM is working with CenterPoint to create back-office systems that will ensure interoperability, integrate the data together, and turn it into useful information. And that information will be the key to giving customers what they want from CenterPoint—better reliability and service.
“Technology has brought different expectations and demands,” Cortez says. “Consumers demand better reliability, and they expect more information and better information. We need to start meeting that expectation to keep customers satisfied. That’s the real driver for building the smart grid.”
Although California and Texas have embraced the concept of a smart grid, and EPRI and the Department of Energy have made progress in defining its elements and objectives, for utilities in many states the concept still remains nebulous. Is it basically more SCADA? Distribution automation? Advanced metering? The lack of clarity makes it difficult for utility decision makers to understand grid intelligence, much less focus on it as a goal. That hinders support for intelligent-grid ideas, investments and ultimately rate-recovery requests.
“It’s a regulatory conundrum,” says Chris Hickman, an executive vice president with CellNet Technology Inc. “Since no one has come up with a discrete definition of ‘intelligent grid,’ it’s hard for utility commissions to give it their blessing.”
To address this and related problems, Xcel Energy is working with various stakeholders to develop a coherent vision of the smart grid. The company established a working group called the Smart Grid Forum to engage technology companies, public officials, policy experts, environmental advocates, and other participants in an effort to define what the smart grid means for Xcel, and to determine how stakeholders can help realize that vision.
As a result of this process, Xcel has identified several potential pilot projects that will advance grid intelligence in specific operational areas. More important, however, the process has led Xcel to an expansive conception of the intelligent grid.
“We are looking at it all the way from the fuel source to the end-use consumer,” Lamb says. “Everything from a lump of coal or a breeze of wind to the thermostat has to be part of the smart grid.”
The reason for this encompassing definition is that all parts of utility operations and services affect one another. For example, concerns about climate change increasingly are driving resource decisions and load patterns, and both have implications for the company’s vision of the intelligent grid.
“The smart grid will result in more efficient use of energy, more effective use of renewables and even will assist a transition toward electric transportation,” Lamb says. “These things will lower society’s carbon footprint, and if that is a driving force then you must also include fuel sources and the consumer’s behavior as you plan the intelligent grid.”
These considerations have immediate and significant implications for Xcel Energy, which has more windpower in its service territory than all but a handful of electric utilities, and a growing number of solar-electric installations in its Southwestern U.S. markets. And in December 2006 the governor of Minnesota—where Xcel is headquartered—set a goal to increase the contribution of renewable energy to 25 percent of the state’s electricity consumption by 2025, with “financial penalties” for utilities that fall short. Accordingly, Xcel’s smart-grid plans include concepts for effectively integrating renewable electricity, maximizing its value on the system, and giving customers better information and options for choosing renewable energy sources.
Developing a clear and comprehensive vision of the intelligent grid is particularly important, Lamb says, as the industry moves into a new phase of infrastructure investment. “If you can take the smart grid to the next level, you can deliver millions or billions of dollars of savings in transmission and generation investments, as well as the environmental impact that goes with them,” he says.
Particularly as utilities face the prospect of mandatory carbon constraints, a power grid that is intelligent from end-to-end will allow electricity prices to reflect the environmental costs of a given kilowatt of power. “I don’t see how the industry can ignore the fuel source in the smart grid, because ultimately that will drive investments and the choices consumers make,” Lamb says.
Indeed, for the industry as a whole, environmental and energy resource considerations might prove to be as important in driving the smart grid as any other motivating factor, including reliability and time-of-use pricing. “Running the grid more efficiently will pay dividends as it relates to generation and environmental costs,” says Valocchi of IBM. “Those issues are top of mind for utility executives, and the intelligent grid is an important part of managing the entire energy value chain.”
Building the intelligent grid might turn out to be the utility industry’s most important challenge in the 21st century, simply because success in so many other areas depends on an intelligent electric power system. And a prerequisite for resolving this challenge is for individual utilities and the industry as a whole to clarify the intelligent grid vision, and describe that vision effectively to customers and regulators.
Such clarity might prove difficult to achieve, from a technical perspective. “The intelligent grid isn’t one thing,” says Von Dollen of EPRI. “Every company will have a different intelligent grid, shaped by the drivers of the geography, the company, and the state’s regulatory structure.” Smart-metering developments in California began with the principle that time-of-use metering would bring benefits to ratepayers and society as a whole—in terms of peak-load management and grid efficiencies. In Texas they were spurred forward by legislation endorsing BPL technology. In Minnesota they are being inspired by the need to get the most from renewable power sources.
Irrespective of such differences, the strategic objectives of the intelligent grid remain consistent in virtually every case—to enable significant improvements in reliability, efficiency and customer service. The specific character and importance of each objective will vary, but the overall intelligent-grid strategy will gain momentum as stakeholders recognize its powerful drivers and benefits.
The natural champions for this strategy are utilities themselves—many of which have heretofore approached the intelligent grid with reluctance, if they have approached it at all. However, capturing the smart grid’s benefits for ratepayers and shareholders will require utilities to adopt grid intelligence as a strategic priority.
“In the broadest terms, it is our job to try to educate consumers, regulators and elected officials about what the intelligent grid can do,” Lamb says. “We are the experts, and we should be shaping the process and the vision of the intelligent grid.”