Much is riding on successful smart-grid deployments. Last fall, the Department of Energy set aside $11 billion for smart-grid creation. On top of that, many utilities are investing millions of their own money in grid improvements within their service areas. The expensive question remains: Will these investments pay off? Lacking a standard path for smart-grid development, utilities nationwide are venturing into unknown territory, putting their smart-grid business cases to the test.
AEP’s gridSMART Ohio Project: American Electric Power (AEP)
• 5.2 million customers
• $14.4 billion revenue (2008)
• Service areas in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia, and West Virginia
• Approx. 39,000-MW generating capacity
• Coverage: 110,000 customers
• Cost: $150 million. The Department of Energy awarded $75 million and the rest is coming through a combination of monies subject to regulatory approval and in-kind donations from vendors that want to participate.
• The Project: AEP’s vast service territory poses significant challenges to implementing advanced grid technology because it encompasses everything from urban and suburban areas to mountainous and rural sections across eleven states. For that reason, AEP is taking a holistic approach with its smart-grid demonstration project in central Ohio. Working in partnership with the DOE, and with General Electric, AEP is investing in advanced technologies to operate the grid more efficiently. The utility aims to achieve this by installing smart meters, distribution automation equipment, demand-response technology, integrated voltage/var control, all the way through to smart appliances and home energy management systems. Smart appliances will help the utility determine how best to control them during peak periods without having a negative effect on residential customers’ lifestyles. The reason for the high $150 million price tag is that AEP is also planning to test community storage technologies, adding plug-in hybrid electric vehicles, and creating a cyber security center.
“Our demographics match the demographics across the nation within a few percentage points,” says Teri Flora, director of corporate communications for AEP Ohio. She’s realistic about the project and expects to see both successes and failures. “We’re confident that we can produce a demonstration project that will allow smart grid to progress across the country.”
• Returns: The utility expects that the improved efficiencies will reduce consumer costs by about $5.75 million over the course of the project. Consumption will be reduced by 18 megawatts and peak demand will be reduced by 15 megawatts. “By maintaining power at the appropriate level, supporting the vars, they’re eliminating waste on their network,” says Mark Hura, global smart-grid leader for General Electric. “They’re more efficient about how they’re delivering that power.” With the integrated volt/var control application alone, AEP is looking at curbing peak demand by up to 2 percent for the customers on the circuits that have the installation.
• Timeline: Smart-meter deployment began in December 2009. Hura says that GE has installed the smart-meter technology infrastructure and the advanced coordinated voltage/var technology on the network. The DMS system is being put into place and smart appliances likely will be in homes by the second half of this year. Some of the installations are expected to continue through summer 2011. Flora says 2010 is a test year for the utility. “Right now we’re still validating data, validating the technology, and looking at pricing options from the consumer side.”
Ultimately, the goal is changing consumers’ perceptions, so they view electricity not as a convenience, but a product they use on a daily basis. “People want to know exactly what they’re buying,” Flora says.
TNMP’s SmartMeter Trial Deployment: Texas-New Mexico Power (TNMP)
• 706,000 customers
• Service areas in Texas and New Mexico
• 300-MW generating capacity (the rest is purchased from other utilities and third-party suppliers)
• $2.5 billion revenue (PNP Resources, 2008*)
*Consolidated operating revenues from continuing and discontinued operations
• Coverage: 10,000 units for residential customers.
• Cost: Undisclosed. TNMP paid for the smart meters out of its operating budget and there was no rate case involved so the amount isn’t public.
• Overview: TNMP’s smart-meter trial in Texas is being done in partnership with SmartSynch, which manufactures IP-based wireless communication equipment for the utility industry that connects to public wireless networks. For the trial, SmartSynch’s wireless communication modules are integrated into GEI210+C digital meters.
“The communication module can fit into anybody’s meter—Elster, Itron, GE,” says Robert Howells, director of program management for SmartSynch. The data bandwidth for AT&T is “massive” while unlicensed radio frequency (RF) mesh networks provide far less capacity, he adds. The argument is that disaster recovery is already built in with AT&T, while a utility would need to buy and maintain that with a mesh network. SmartSynch’s system takes the data collected by each meter, encrypts it, compresses it, and then sends it out over AT&T’s network to a transaction-management system, allowing TNMP to make remote disconnects and reconnects, monitor for outages, and receive notification about a power restoration.
• Returns: While the financials for the smart-meter trial deployment aren’t publicly available, SmartSynch reported in May that TNMP had achieved a 99.96-percent average daily read rate on its 10,000 units in the Texas market. SmartSynch says TNMP also is saving money by avoiding having to build a mesh network and then hire personnel to maintain it. In a statement about the smart-meter trial deployment, Neal Walker, TNMP’s vice president of operations, said that SmartSynch’s use of public wireless networks offers the utility enough bandwidth to use the best security technology on the market.
Over the past year, the smart-grid communications market has been heating up. Verizon also has formed smart-grid partnerships with vendors. Even municipal WiFi company Tropos has repositioned itself as a smart-grid network provider for utilities, saying that its networks have a 3.5-year ROI. With all this competition, utilities might look forward to a wider range of options to fit their goals and budgets.
• Timeline: The partnership between TNMP and SmartSynch began in fall 2007 and the smart-meter deployment began last fall. According to Howells, installations are continuing with a little over 11,000 in use now. Over the next month or so approximately 1,500 more will be put into place.
Westar’s SmartStar Lawrence Project: Westar Energy
• 684,000 customers
• Service areas in east and east-central Kansas
• 7,100-MW generating capacity
• $1.858 billion revenue (2009, total revenues)
• Coverage: The city of Lawrence, Kansas, including approximately 48,000 meters.
• Cost: $40 million, with $19 million from the DOE and the rest from Westar.
• Overview: This large utility based in Topeka, Kansas, describes its smart-grid approach as cautious but meaningful. The vision for the SmartStar Lawrence project is to gather enough statistically significant data to roll out the most effective measures in the rest of the Westar service area. In addition to nearly 50,000 smart meters, Westar is installing a range of equipment, including automated distribution, a smart grid-enabled outage management system, and internal IT updates.
Both customer service and communication are at the forefront of the project, says Hal Jensen, Westar Energy’s director of SmartStar Programs. The plan is for customers that have Internet access to be able to monitor their electricity use daily and set personal preferences so they receive alerts when their bill is about to reach a certain threshold. Through the project, the utility also wants to determine the best ways to communicate with its customers, whether that means through a Web portal, email, text messages, and even social media tools.
“A lot of this is just figuring out the best suite of services that we can offer that will be effective for everyone involved,” Jensen says. “We want to continue to build a very strong relationship with our customers and continue to be a trusted energy advisor to them.”
Westar is working with eMeter on the Lawrence project, which Jensen says is an advantage because the vendor brings innovative customer marketing experience to the table. “We may be the only choice that the customers have right now but we certainly don’t want to act like it,” Jensen says. “We’ve always said among ourselves here that the best time to build customer loyalty is when you really don’t have to.”
• Returns: Two-thirds of the financing is for the back-end information technology infrastructure, which includes AMI, a meter-data management system, a customer Web portal, and a smart-grid enabled outage-management system, Jensen says. Those technologies are being installed in a way that they will support all of Westar’s customers system-wide while smart meters and localized distribution automation will be unique to Lawrence. Historically, Westar has a high level of customer service, Jensen says. “We think that type of relationship can lend itself to more understanding and more participation in the types of programs we can offer that may have a financial benefit for us—things like potential to defer future generation.”
• Timeline: Westar filed for DOE funding last August and an agreement was signed in March for the three-year project. Planning and internal technology installations will take place during the second quarter of this year through to year end with the meter-installation process, optional customer pilot programs, and customer feedback channel implementations all beginning in 2011.
BGE’s Demand-Response Infrastructure Program: Baltimore Gas and Electric (BGE)
• 1.2 million electric customers
• Service area in Baltimore, Maryland
• 6,200-MW generating capacity (from holding company Constellation Energy Group)
• About $2.68 billion (2008 regulated electric revenues)
• Coverage: 420,000 residential customers.
• Cost: The overall cost of BGE’s comprehensive smart-grid initiative is $500 million. The demand-response infrastructure program is a subset of this initiative and the cost has not been made public.
• Overview: Rate freezes recently expired in Maryland, and as a result BGE instituted two rate hikes. To reduce energy usage and help customers lower their bills, the utility launched a demand-response infrastructure program in 2008 that’s expected to enroll 420,000 customers over the course of 40 months—a rather high 47-percent penetration. In the program, customers have a choice of getting an air conditioner switch that mounts outside the home or a Honeywell Utility Pro thermostat that mounts inside and is professionally installed. Both the thermostats and AC switches have Cooper Power modules that connect the devices via radio signal back to BGE.
On a hot afternoon in July, the utility can send a signal to participating customers’ AC units or thermostats. The AC unit then will cycle so that it’s off when a neighbor’s unit is on and vice versa, except the resident only experiences a temperature rise of about three degrees. “We’ve had a great acceptance rate and very little dropout,” says Steve Smith, sales and marketing director for Honeywell Utility Solutions. Honeywell makes the thermostats and is also delivering the marketing, field implementation, and customer service for the program.
• Returns: During the summer peak, BGE relies heavily on imported power supplies so the demand-response infrastructure program is one way of addressing this challenge. The utility estimates that its program will cut peak energy use by 600 MW over the next two years, which is about as much as a mid-sized power plant generates. For customers, the thermostats and AC switches can reduce energy costs by up to 20 percent.
• Timeline: The program officially launched in early 2008 and should reach maximum enrollment by June 2011.
Volt/Var Conservation Voltage Reduction Program: Modesto Irrigation District (MID)
• 111,379 customers
• Service area in California
• 700-MW generating capacity
• About $299.9 million revenue (2006 electric revenue)
• Coverage: More than 100,000 customers in its area.
• Cost: $1.5 million from a DOE grant.
• Overview: Modesto Irrigation District is a customer-owned multi-service utility that has long kept a close eye on regulatory activity in the state of California. “There was a big push in demand response, less generation, renewable portfolio standards, greenhouse-gas standards,” says Tom Kimball, assistant general manager for transmission and distribution at MID. “We did a benefit-cost analysis on the types of systems we were looking at to see if they made sense for the organization.” So, about 10 years ago, the utility began a trial advanced-metering infrastructure system.
Over time, the utility implemented automated meter readings, allowing it to save on manpower costs. But the system wasn’t entirely hardcore savings. The payback time initially looked like it could be anywhere between eight to 15 years. “However, the payback drops dramatically based on how much demand response you can achieve by it,” Kimball says. With the DOE grant, MID is now looking at using its meters as part of a voltage/var control and conservation voltage reduction program in order to lower demand. “We think that can be an effective demand-response tool.”
• Returns: MID performed some trials on its system for running the distribution circuits at minimum utilization voltage. Manually, the utility saw 2 to 3 percent potential savings on demand during summer months. “That’s huge,” Kimball says. “Once we get the system up and it can perform that automatically with our substation load tap changers and our capacitor controls for power factor control, as well as our voltage sensing that’s coming out of our AMI meters—if that all really works—it can be a huge saver.” The utility also hopes to see a 5-percent reduction just from time-of-use rates, but that will be tested as well to see if the savings are achievable.
• Timeline: MID plans to start its pilot volt/var conservation voltage reduction program in the third quarter of this year. Time-of-use rates likely will be introduced next year, along with a voluntary program for residential customers to show them what their energy usage is in order to achieve additional demand reduction.