An Evolving Industry

Many promises have been made about the newest generation of smart meters and the potential for two-way communications between utilities and their customers (or, rather, their customers’ connected devices). Often overlooked, however, are the opportunities these virtual conversations will create. One effort is underway in Illinois to apply that data to tie real-time electricity use to related greenhouse gas (GHG) production, and it could give that state’s regulators a new way to evaluate utility performance.


In 2011, the Illinois General Assembly overrode a veto by then-Gov. Pat Quinn to enact the Energy Infrastructure Modernization Act, known locally as the “smart grid bill,” which provided ratepayer support for up to $3.2 billion in grid-modernization upgrades. It included a statewide conversion to digital, addressable electricity meters from old-school, analog models. Environmental and consumer groups saw the minute-by-minute data that would be generated by these new meters (as well as by other sensors throughout the improved grid) as a potential resource in their efforts to reconsider traditional compensation models for electric utilities.


“In the past, they received a rate of return on their investment. Why not reward them on a portfolio of performance criteria?” said Dick Munson, Midwest director of clean energy for the Environmental Defense Fund (EDF), describing ideas his group was sharing with consumer advocates from Illinois’ Citizens Utility Board (CUB).


One such criterion was obvious to 
the EDF.


“As an environmental group, we’re interested in how pollution gets reduced,” he said.


Executives at Commonwealth Edison (ComEd), Illinois’ largest utility, also were exploring alternative revenue models and were open to ideas as to what characteristics a performance-based rates approach might incorporate. Understanding that peak-demand periods often drove increased reliance on less-efficient and high-polluting generation resources, the EDF, CUB and ComEd considered the energy-efficiency and demand-reduction programs that are the backbone of many states’ efforts to encourage customers to use less electricity. When it comes to reducing GHG emissions, not all kilowatt-hours are created equal.


“A kilowatt-hour saved during a high CO2-use time is more valuable,” ­Munson said.


Thus came the idea to tie usage data from smart meters to the real-time output of the generation plants—along with solar arrays and wind farms—that supply their delivery system. The result is a “variable carbon value” of a kilowatt-hour of electricity for each of the 8,760 hours that make up a year.


With this tool, ComEd has an objective means for quantifying how effective various incentives, investments and energy mixes are in meeting a goal to reduce GHG emissions related to the electricity they sell. It even can be applied to operational changes—e.g., reduced emissions from the elimination of meter-reading vehicles—thanks to the move to meters that can be read remotely.


While the EDF, the CUB and ComEd see a lot of promise in this new methodology, exactly how it might be implemented in any kind of revised compensation program has yet to be executed. Currently, the team is working through an analysis of the first year’s data to try to understand how widely the new metric might be applied.


“It leads us to ask a lot of questions,” Munson said, including where new 
distributed-generation resources might best be introduced. He also believes the technology could prove favorable in states such as Minnesota, where utilities, environmentalists and regulators are attempting to place a value on rooftop and community solar systems that addresses benefits beyond the per-kilowatt cost of electricity from the generation resources they are displacing.


“I think it’s actually critical for that conversation. You get to see where distributed generation is of value,” he said.


Fortunately for ComEd, Illinois residents are less resistant to the idea of smart meters than customers in other utilities’ service territories. In states such as California, Maryland and Texas, a small, but vocal, minority of customers has fought to opt out of such installations. However, Munson said the new GHG metric would still be meaningful at levels less than full, territory-wide deployment.


“As you get to some level of deployment, you could begin to extrapolate about how it could be expanded out to the entire service territory,” he said. “It’s probably less than 50 percent.”


For Munson, this new measurement tool is an introductory example of the benefits smart meters, grid-based sensors and other such equipment will provide to utility operations, system reliability and current initiatives, like those the EDF promotes, to reduce the impact our energy demands have on the environment.


“The key component of it is data, and how we manipulate that data can have substantial benefits,” he said. “That’s the exciting part of the evolving electricity industry.”

About the Author

Chuck Ross

Freelance Writer

Chuck Ross has covered building and energy technologies and electric-utility business issues for a range of industry publications and websites for more than 25 years. Contact him at chuck@chuck-ross.com.

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