Utilities’ Smart Grid Investments ‘Conceptual’

By Published On: July 8, 2011

In one of the most ambitious efforts in recent history, California’s investor-owned utilities outlined plans to spend $5.5 billion to transform the state’s grid by installing an extensive network of automated digital controls linked by a new high-tech communications system. The so-called “smart grid” plans, according to the trio of private utilities, aim at integrating more intermittent renewable energy and paving the way for widespread use of electric vehicles. The plans come on top of $5 billion the utilities already are spending on installing digital meters. The utilities contemplate different scopes for their respective smart grid futures in documents filed with the California Public Utilities Commission June 30-July 1. Pacific Gas & Electric’s preliminary plan is the boldest. PG&E projects its infrastructure overhaul costs and benefits looking forward 20 years, far longer than San Diego Gas & Electric and Southern California Edison. Edison’s smart grid deployment plan looks out to 2020, but outlines costs for only four years. San Diego Gas & Electric projects costs nine years into the future. All three utilities adopted the CPUC mantra of consumer “empowerment.” In a cautionary note, all the utilities characterized their estimates for the costs and benefits of grid modernization as uncertain at this stage. PG&E, for example, stated its estimates are “conceptual, preliminary and subject to significant change.” The utility also predicted it expects “the scale of deployment and market conditions” to undergo significant changes over the next 20 years. PG&E predicted the cost of upgrading its grid at between $850 million and $2 billion over two decades. That figure does not include $2 billion spent on installing advanced digital meters or other previously-approved smart grid investments. Edison plans to spend $1 billion on smart grid deployment from 2011 through 2014. It also plans to finish installing smart meters at an additional cost of $803 million in 2011 and 2012. Some of the $1 billion includes operation and maintenance after capital projects are completed, according to the utility’s plan. Yet, even though Edison projects costs for just the next several years, it warned the commission the estimates could vary by as much as plus or minus 45 percent, reflecting the uncertainty of both the pace and changing technology involved in moving toward a smart grid. On top of the already approved $1 billion for SDG&E digital meters and other grid projects, the utility intends to spend $1.4 billion in its next general rate case cycle; another $237 million on enabling time-of-use customer response; and about $900 million in transmission and distribution infrastructure by 2020. The three utilities touted their grid modernization plans would accommodate a greater amount of renewable energy--both into the distribution and transmission systems--plus ready their circuits for a surge in electric vehicles and more customer interaction through demand-response initiatives. While a “smart” grid allows for more real-time information on energy use and its costs to consumers, residential real-time tariffs remain illusive. Utilities also see the digitized grid as a way to more accurately forecast supply and demand, more quickly respond to outages, and provide better voltage support and more energy storage (see sidebar). In its regulatory filing, PG&E broke down costs into up to $125 million in capital investment--for which it is to reap an up to 11.35 percent rate of return--and between $500-$800 million in operating expenses over 20 years. Major costs included in the estimated $2 billion price tag are “advanced distribution automation” at a cost up to $850 million and $295 million for cyber security. PG&E estimates potential benefits for customers at between $900 million and $1.9 billion. That includes up to $1.4 billion in avoided energy purchases for PG&E. On the benefits side, Edison projects enrollment in demand-response programs increasing from 1,530 MW of customer load to 1,900 MW by 2014 with the roll out of digital meters. The utility projects the new meters alone to enable 1,000 MW of peak demand reduction by its customers by 2017. Edison cites additional benefits, including fewer and shorter outages and higher quality power for its customers, as well as savings on operating costs due to increasing system automation. The utility also stated its smart grid investment is instrumental to integrating higher levels of both central and distributed renewable generation facilities into its grid. The plan too envisions accommodating 450,000 plug-in electric vehicles by 2020 and phasing out old coastal power plants within its distribution system that rely on once through cooling with ocean water. Edison said implementing what it dubs WAMPAC (Wide-Area Monitoring, Protection, and Control) is instrumental in transitioning to a smart grid. WAMPAC technology, according to Edison, enables monitoring the grid for instability and needed rapid automated responses--such as load shedding and generation tripping. Edison envisions its WAMPAC system will monitor transmission throughout the West, particularly as the number of intermittent wind and solar plants feeding the region’s bulk transmission system grow. San Diego Gas & Electric calls its benefits estimate an “inexact science.” “Nascent and future technology, inability to predict customer adoptions rates, lack of models to value benefit, economic fluctuations, and environmental policy” are factors, according to the utility. It couched that lack of certainty in the face of new investments by adding, “The opportunities for further benefits are limited only by our imagination.”

Share this story

Not a member yet?

Subscribe Now