by Kathleen Davis, senior editor
President Barack Obama signed the American Recovery and Reinvestment Act (ARRA) into law in early 2009.
Since that flourish of the presidential pen, utilities, regulators, associations and vendors have benefited from an influx of funds into the smart grid vision.
“The investment we’re making today will create a newer, smarter electric grid that will allow for broader use of alternative energy,” Obama said at the time.
Two years later, ARRA funding is at work across the U.S. in areas as diverse as synchrophasors and program oversight. The smart grid will be achieved by traveling a path paved primarily with government money, but how is that journey progressing?
More than 300 recipients have been given ARRA cash, including:
- 99 for Smart Grid Investment Grants (SGIGs) with a total obligation of $3.48 billion,
- 42 for smart grid regional and energy storage demonstration projects with a total obligation of $684 million,
- 52 for work force development programs with a total obligation of $100 million,
- Six for interconnection transmission planning with a total obligation of $80 million;
- 49 for state assistance for electricity policies with a total obligation of $48.62 million,
- 50 for enhancing state energy assurance with a total obligation of $43.5 million,
- 43 for enhancing local government energy assurance with a total obligation of $8.02 million, and
- One for interoperability standards and framework with a total obligation of $12 million.
The support of the program has been allotted an additional $27.81 million on top of the awards listed. (See Figure for cumulative federal ARRA payments as of August.) A wide range of activity and funding levels exists within the categories.
Specifically under the SGIG label, projects range from deploying multiple smart grid technology systems at Southern Co. to enhance efficiency, security and automation to installing 38,000 smart meters at Cheyenne Light, Fuel and Power Co. in Wyoming.
Smart grid regional demonstrations include cybersecurity and electric vehicle (EV) studies at Los Angeles Department of Water and Power, an integrated and scalable full-system smart grid model at Southern California Edison, time-of-use and critical-peak pricing concepts at NSTAR, military-grade cybersecurity at Boeing, and fault current limiting superconducting transformers at Waukesha Electric Systems Inc.
Following is a summary of five—three utilities and two on the transmission side of the grid equation.
Utility View: GWP
Glendale Water & Power (GWP) in southern California was one of the first utilities awarded ARRA funds for its smart grid projects—specifically smart metering.
The utility’s smart metering project covers 120,000 customers. GWP installed the project’s last Itron smart meter during a September ceremony at Glendale Community College.
The ARRA funding helped accelerate GWP’s smart grid plan from a narrowly focused five-year project to a broader, three-year project, said Glenn Steiger, GWP general manager.
“Glendale would have pursued the smart grid project regardless,” he said, “but thanks to the funding, we are beyond our set schedule and moving forward rapidly.”
GWP’s project runs across power and water with smart meters, smart water communication modules, a meter data management system, leak-detection technology and customer Web portals.
The project gives customers better management options, allowing informed consumer choices that save money and help the environment, Steiger said.
The utility expects to move forward with smarter customer interactions by using data collected through smart meters.
GWP wants to display that information in digital picture frames inside customers’ homes, making the information customizable.
Cloud information is a part of GWP’s in-home display step for customers’ future.
The company making those digital picture frames, Ceiva, stores pictures in the digital cloud format. Using the same ZigBee chip, communications can run from meter to real-time display.
Customers can display energy information and private photos on the digital frame, Stegier said.
Utility View: City of Fort Collins Utilities
The city of Fort Collins (Colo.) Utilities received $18.1 million in Department of Energy (DOE) funding to develop an energy management system. The project includes the installation of 79,000 smart meters and in-home demand response systems that include in-home displays, smart thermostats and air conditioning and water heater control switches, along with system automation and security. (Siemens and eMeter recently were selected as vendors for this project.)
Fort Collins Utilities Senior Electrical Engineer Dennis Sumner expects customer benefits to range from reduced costs for billing services with rate options to improvements in service quality.
The utility anticipates more EVs will be plugged into the community, as well.
The project will provide the utility “options to stabilize distribution system load impacts and offer customers more cost-effective options for charging,” Sumner said.
The basic plan for the Fort Collins smart metering project was in the works before ARRA funding became available, Sumner said.
The utility already had been putting together a recommendation on smart grid options for its governing board. The ARRA SGIG funding, however, allowed the utility to expand on the original concept in demand response, distribution automation and cybersecurity.
“We view our AMI investment as a means to facilitate significant paradigm shifts in our service relationship with customers in the future,” Sumner said. “Next steps on our path will include expanding the information outreach and support services available to customers, alternative rate options and increased control capacity for customers.”
The project, Sumner said, will help bring in more distributed energy resources and plug in renewables to the system, as well as support the first phase of a communitywide broadband wireless communications network.
Utility View: OG&E
Oklahoma Gas & Electric Co. (OG&E) is partially funding a $293 million update with ARRA cash. The utility plans to install smart meters, automated switches, circuits and capacitor banks.
The first phase involving 3,000 customers in a pilot study on pricing plans and consumer response was finished in 2010. Dropout rates were low, and about 98 percent of customers expected savings. To verify results, OG&E expanded the study by an additional 3,000 customers in 2011.
OG&E expanded testing of smart grid technology with an additional 42 circuits equipped with capacitor controllers and 16 circuits with automatic reclosers. (The circuits are to assist with integrated volt/VAR control to reduce peak demand.) Like the consumer study, a 2010 test on residential circuits was conducted in Norman, Okla. Results could reduce demand 0.8 percent to 2.4 percent, according to OG&E.
“To some that doesn’t sound like much,” said Ken Grant, managing director of OG&E’s smart grid program, “but to those of us in the utility industry, it represents another opportunity to delay the need to build new fossil fuel power plants until at least 2020. Two of the key benefits for smart grid technology are improved efficiency and reliability.”
ARRA funding sped the smart grid process, Grant said. The utility was already up to the elbows installing grid technology in Norman when it found out about the award. Covering some 40 percent of the project’s overall cost, the extra money helped expand the Norman-based beginning to the utility’s entire service area.
OG&E’s benefits-based approach centers around customer service. The smart grid upgrade will “put more tools in customers’ hands so they can better manage their energy,” Grant said.
The continued expansion of smart grid technology across OG&E’s territory remains its goal, along with integrating the distribution management system, Grant said. That integration should improve reliability and allow for quicker restoration. The utility also will focus on data and enhanced analytics to further improve operating efficiencies, he said.
Smart grid funding isn’t set aside only for utilities to pop in smart meters or engage consumers. Cash moves right up to the transmission level.
The Western Electricity Coordinating Council (WECC) received a $14.5 million grant to expand transmission-planning activities in the region. WECC recently released a 10-year plan to outline efforts, including transmission expansion, policy changes needed and potential costs. As with efforts of GWP, Fort Collins and OG&E, funding accelerated an effort languishing in regulation and investment limbo.
The government cash helped the council “expand the breadth and depth of its existing interconnectionwide transmission planning activities,” said Bradley Nickell, WECC director of transmission planning.
It allowed for more input in the planning process, more analysis and the procurement of planning tools, he said.
WECC is the largest of the eight regional entities that work with the North American Electric Reliability Corp (NERC). Its service territory starts at Canada and goes south along the western U.S. edge to Mexico.
WECC’s 10-Year Regional Transmission Plan examines what the area might look like soon, factoring in options, choices and scenarios.
“The plan provides insights on reliability, costs, environmental impacts and water usage using a set of consistent assumptions and an open, stakeholder-drive process,” Nickell said. “This has not been done before.”
While developing this plan, WECC allowed for that consistent set of assumptions, including the assumption that all 44 regional transmission projects identified in its foundational projects list will be completed by 2020.
If that remains on track, WECC expects the area will have sufficient transmission capacity to meet load and renewable portfolio standard requirements during the next 10-year planning period. WECC wants a second look at two transmission pathways (from Montana to the northwest with Path 8 and some Pacific interties with Path 65 and Path 66).
WECC is planning for the next cycle. Information will be released in 2013. In addition, the council leads the Western Interconnection Synchrophasor Program (WISP), another DOE-funded smart grid initiative that looks at system vulnerabilities on the Western bulk electric system. That program is scheduled for full implementation by April 2013, Nickell said.
Other programs are in the works with ARRA funding.
Synchrophasors could leap the U.S. grid way ahead of the current game. Now, monitoring technology is slow. Using phasor measurement units (PMUs), utilities could record information from a line at the rate of 30 to 120 times per second—about 100 times faster than today’s technology.
The term synchrophasor is “a calculated measurement of the magnitude and phase angle of voltage or current between two points on the grid, time-synchronized against GPS,” said Alison Silverstein, North American Synchrophasor Initiative (NASPI) project manager. ASPI is a voluntary organization to promote synchrophasor adoption.
There are many benefits to the PMUs’ time-stamp of each measurement. Put together across a region and a time period, these stamps give an accurate overview of the whole system. NASPI and others have likened the overview to an MRI for the grid.
SGIG funding has launched 10 synchrophasor projects since the awards were announced in 2009. The projects involve 57 utilities and grid operators and 850 networked PMUs. (The DOE estimates that by 2013 PMUs will be at work in nearly all U.S. regions.) Together the projects make up the largest synchrophasor effort undertaken, according to NASPI and the DOE.
Before SGIGs, the U.S. had installed some 250 PMUs, many of them what NASPI labels “research-grade.” The data quality was inconsistent, and maintenance on the units wasn’t always at the top of a utility’s list.
Silverstein said SGIGs have pushed manufacturers to better production-grade PMUs built for industry hurdles. In addition, SGIGs have made executives more aware of other PMU projects, as well as their own, engaging the executives in the process. SGIGs also upped the speed limit on that road to a future smart grid, she said.
“Before SGIG, our road map called for a 10-plus year synchrophasor deployment effort,” Silverstein said. “Today, we’re looking at half that time or less.”
The ARRA funding for regional PMU deployment has been huge, she said. The acceleration of PMUs from this project could mean 1,000 deployed across North America by 2014, feeding high-speed data about grid conditions into control rooms across the grid.
Phasor data will let operators manage the grid “with greater reliability, help them identify and avert potential reliability problems before they get out of control, and help to integrate intermittent renewable generation while getting more transmission out of the grid we’ve got,” she said.
ARRA funding might not have started smart grid efforts for utilities and transmission entities, but it boosted applications, integration and scope with each project. ARRA beefed up distribution and transmission sides of smart grid development during the past two years.