No question, 2012 is shaping up to be a critical year in utility smart grid deployments. The last 12 to 24 months have been a time of intense learning, some of it painful. Look for more of that over the next year or two.
Gradually, early-adopter utilities are getting a sense of what works and what does not in their smart grid deployments. Surprises — welcome and unwelcome — have been the norm, not the exception, as utilities scour data for key insights to make their smart grid investments more effective, politically palatable and successful (see “Five Leaders Share Cautions and Recommendations”).
Over the last 12 to 24 months, several utilities have been surprised by adverse regulatory rulings and customer pushback around smart meters. Going forward, utilities vow there will be fewer surprises from the regulatory commissions, because they will do more homework with their commissioners and commission staff.
Also, there will be more stakeholder engagement at the front end of a smart grid or smart meter project. Referring to Pacific Gas and Electric's (PG&E's) smart meter problems in Bakersfield, California, U.S., Karen Lefkowitz, Pepco Holdings' vice president of business transformation, said, “Utilities must be prepared for their Bakersfield moment, because if we don't effectively manage customers' concerns, these projects could blow up in our face.”
A Customer-Facing Project
Utility leaders and smart grid project managers rightly spend a lot of time on the technological and engineering challenges posed by the smart grid. Technologies have to perform as advertised. Transmission and distribution networks need to be altered. Business processes need to be modified.
No one minimizes the magnitude of those challenges. But, Lefkowitz makes another compelling point, “Although we talk a lot about the technologies being deployed in smart grid programs — and, in particular, the communications technologies — we must remember that the smart grid is not just a technology project. It uses technology to deliver customer benefits. It is a means to an end, not an end in itself.”
Lee Krevat, smart grid director for San Diego Gas & Electric (SDG&E), agrees, “It is possible to select the right smart grid equipment, whatever it may be, and install it properly, but if we don't get the people part of smart grid right, the projects will fail.”
Who Benefits? Who Pays?
In the not-too-distant past, circa 2009, before the industry began amassing data on the costs and benefits of smart grid projects, it was generally accepted a significant chunk — perhaps the majority — of the benefits of the smart grid would be captured by customers using smart meters. In the early years of the smart grid, smart meters received a lot of industry buzz while the internal, operational benefits of the broader smart grid endeavor garnered less attention in many quarters.
Over the last year or so, that perspective has changed, as much by consumer reaction to smart meters as by the growing evidence a large amount of benefits may be created in utilities' internal operational areas.
At a 2011 conference sponsored by KEMA, David Eves, president and CEO of Public Service Company of Colorado, an Xcel subsidiary, estimated 70% of the value of his utility's smart grid investment will be in the transmission and distribution system.
Barbara Lockwood, director of energy innovation for Arizona Public Service Co. (APS), generally agrees with Eves. She said her utility has seen significant operational benefits from its smart grid projects, which will “help extend the life of the utility T&D infrastructure and lower maintenance costs.”
She was more tentative regarding quantification of customer benefits so far. “We're still working to quantify the benefits to customers,” she reported. “A self-isolating circuit we installed in Flagstaff, Arizona, U.S., avoided about 600,000 minutes of outages in about a year. In one particular instance, the self-isolating technology installed on the distribution system let us turn a potential 40-minute outage at Flagstaff City Hall into a momentary flicker.”
Pepco's Lefkowitz noted the utility's smart meter investments allowed it to remotely close 582 outage tickets in its Delaware, U.S., service area after Hurricane Irene. “We were really pleased with how the system worked after Hurricane Irene. Anytime you can avoid a truck roll, that's good.”
In reality, it is futile to try to put one cluster of benefits into a bucket labeled “customer benefits” and another cluster into a second bucket named “internal utility benefits.” Benefits are accruing in both areas, in ways that are financial as well as nonfinancial. “The right smart grid technology and deployment should create benefits for both customers and utilities,” said Doug Kim, director of advanced technology at Southern California Edison (SCE). “Better-quality asset management brings benefits to customers, as well. It's a both/and situation, not either/or.”
If the last 12 to 24 months was a period of learning from field deployments, the next 12 to 24 months promise to be an equally challenging time of learning in the public utility commission hearing room.
Many utilities have a large and growing capital spending program, driven by the following, among other things:
The need to replace aging infrastructure
The need to comply with mandated state renewable energy standards
The need to clean up or close older coal-fired generators to comply with new environmental regulations.
“We have no shortage of investments right now, including nearly US$1 billion in solar generation,” said APS's Lockwood. She also said the utility is currently looking at its smart grid communications platforms and will consider leasing bandwidth from other telecommunications providers as well as building it (see “Telecommunications Networks: Own or Lease?”).
State utility regulators are being “very, very cost conscious these days. How much financial burden do they want to place on customers? Very little,” said Pepco's Lefkowitz. She said, “We evaluate all communications approaches, leased or owned, and select the one that best meets cost and operational requirements.”
Matching Technologies with Needs
The U.S. Securities and Exchange Commission and the California Public Utilities Commission are investigating the costs and benefits of allowing a utility to put its lease costs into a rate base, and thus earn a return on them.
However, as these own versus lease discussions progress, there is a white elephant in the room that few, if any, participants want to acknowledge. The industry is installing new technology at a rapid pace. This carries high risks, which translates into upward pressure on electric rates. No one wants to talk about increasing rates today to pay for benefits that may not become clear for several years, if ever.
Many regulatory and legislative mandates fit the definition of “moral hazard” — an initiative that does not fully consider impacts because the costs are being paid by someone else. In effect, regulators and legislators are playing with other people's money. There is concern that when the music stops and the bills have to be paid, utilities will be forced to pay for mandates enacted by regulators and lawmakers. These costs include the undesirable, but necessary, equipment and operational failures as the industry goes through a protracted, intense learning curve.
Dozens of utilities are implementing smart grid programs. This robust array of field deployments has confirmed one fundamental truism: When it comes to the communications technologies necessary to enable smart grid deployments, one size does not fit all. When one thinks about the geographic size and diverse terrains utilities must serve, this truism may not be surprising. Utilities like PG&E often serve an area that ranges from very densely populated urban areas to very sparsely populated rural mountain regions.
The volume of data generated and latency are two of the most critical factors in determining which communications technologies a utility uses for its various smart grid projects.
Road Map for 2012 and Beyond
Some mission-critical applications tolerate virtually no latency in their communications networks. One example of this is the synchrophasor technologies PG&E is installing in high-voltage transmission systems in the West, in collaboration with a handful of other utilities. “The synchrophasors take up to 60 measurements per second and give us much better intelligence into the way that the high-voltage transmission system works,” said Kevin Dasso, PG&E's senior director for smart grid and technology integration.
Other smart grid applications are less time sensitive; data can be transmitted over a period of hours or days instead of seconds or fractions of a second. For example, for most smart meter applications, the longer latencies offered by mesh radio are acceptable.
“As with most things involving our industry, choice of communications platforms involves a number of trade-offs,” said Jeff Nichols, SDG&E's director of information technology infrastructure. “We have found that no single communications technology works optimally in all settings.” The trade-offs SDG&E uses to evaluate communications technologies include cost, coverage, capacity, security and operational integrity.
Utilities are going through a vertical learning curve on the smart grid and the communications platforms needed to realize its benefits. During this acute period of learning, when frontline experience is at a premium, smart grid leaders offered some words of wisdom for their colleagues at other utilities.
It takes time to turn raw data into actionable intelligence, acknowledged APS's Lockwood. “We're still in our infancy regarding turning data into intelligence. This year, we're going to spend more time understanding the actualized benefits from our existing projects and further developing the business case based on operational benefits within the utility.”
Five Leaders Share Cautions and Recommendations
“We could end up having several dozen smart grid pilots because we need to respond to the ever-changing needs of society and its leaders,” said SCE's Kim. “That may be true at your utility, too. We expect the smart grid will help us more effectively utilize our assets so we don't have to make such sizable investments to serve customers in the future.”
Kim urges other utility leaders to spend plenty of time — perhaps more than they think is necessary — educating and engaging all of their stakeholders, including regulators, legislators, customers, employees, business groups, vendors and even investors. “When the pilot programs end and you go to full-scale deployment, you will be glad you made that investment.”
John Egan is president of Egan Energy Communications, a utility-industry communications consulting firm. Before that, he was a reporter and editor at The Energy Daily, a spokesman for Salt River Project and a research director at E Source.
Kevin Dasso, senior director, smart grid and technology integration, Pacific Gas and Electric: “You only have one chance to make a good first impression. It's important that the technology works, and it works for customers. You have to be able to tell customers what's in it for them.”
Doug Kim, director, advanced technology, Southern California Edison: “This is a long journey. It's critical to develop a strong strategy and a clear road map with specific milestones. Take time to create links across internal stakeholders.”
Telecommunications Networks: Own or Lease?
Lee Krevat, director, smart grid, San Diego Gas & Electric: “Don't get locked into proprietary technology that limits your options. Standards change, technologies change and customer needs change; don't let yourself get put in a box.”
Karen Lefkowitz, vice president, business transformation, Pepco Holdings: “We live in an era where a small group of dedicated stakeholders can create lot of controversies and problems for smart grid deployments. Regulators and legislators are compelled to listen to those concerns. You need to engage with your stakeholders early and often.”
Barbara Lockwood, director, energy innovation, Arizona Public Service: “Take it slow until you understand the operational benefits and customer needs around smart grid. Learn from others — no one is doing everything, but everything is being done by someone.”
When it comes to deciding whether it is better to own the telecommunications assets necessary to support smart grid deployments or lease them from a third party, utilities are all over the map.
Southern California Edison's Doug Kim, director of advanced technology, says his utility typically owns and operates its own fiber-optic and radio networks to relay data around its system. “We built it, we operate it and we own it. From our perspective, ownership of these assets works out best from the perspectives of safety, affordability and reliability.”
Other utilities say they are comfortable with a mix of owned and leased telecommunications assets.
Interestingly, utility regulators are considering control issues, not only costs, in their lease versus build decisions. If a utility contracts with a third party, regulators can only assess the transaction from one vantage point — the utility's side. But they can view both sides of a transaction if a utility transmitted smart grid data over a communications network it built, owns and operates.
Arizona Public Service Co. | www.aps.com
California Public Utilities Commission | www.cpuc.ca.gov
KEMA | www.kema.com
Pacific Gas and Electric | www.pge.com
Pepco Holdings | www.pepco.com
Public Service Co. of Colorado | www.xcelenergy.com
San Diego Gas & Electric | www.sdge.com
Securities and Exchange Commission | www.sec.gov
Southern California Edison | www.sce.com