We all associate the middle of April with taxes. For utilities in Minnesota, the first of April also means it is time to file Annual Smart Grid Reports. Back in March, the Minnesota PUC issued a notice clarifying the information sought in the reports. Cooperative and municipal utilities were asked to voluntarily file the reports so the Commission can obtain a full assessment of smart grid development in Minnesota. The following topics are discussed:

  • “Smart” functions enabled with existing infrastructure and systems, including what percentage of the utility’s meters are currently mechanical, AMR, or AMI, and commentary on the capability of each
  • Planned or completed system improvements which could affect customer service, power quality, or service quality metrics
  • Current customer access to data, such as usage or outage data, and how that data educates customers and whether or not there is any planned additional customer access to data
  • Time-varying rates and demand response
  • The general costs of completed or planned projects, including the costs of changes to billing systems and, if applicable, the early retirement of meters or other equipment when compared to the benefits realized or expected to be realized

The reports can be found at the Commission’s generic docket on smart grid. The MPUC’s home page has a consumer-friendly smart grid FAQs page. Here is an interesting excerpt:

“Has the MPUC authorized cost recovery for smart grid equipment, such as smart meters/AMI?

The Commission has authorized cost recovery for any type of equipment where the cost is incurred reasonably and prudently, whether or not it is smart grid-related. Utilities have already submitted proposals for projects that could be considered to include smart grid equipment and would be granted cost recovery on a case-by-case basis. There is no single decision where the Commission has stated it will automatically grant cost recovery for smart grid equipment, because the Commission first would review the specific project to ensure costs are reasonable.”

On February 8, 2011, George Jepsen, attorney general for the State of Connecticut submitted a brief requesting the Department of Public Utility Control reject CL&P’s AMI deployment plan, citing the $500 million dollar ratepayer-funded plan would yield few benefits. Since CL&P customers already benefit from AMR meters, the AG does not believe the price tag is worth the near term deployment of AMI meters. In the event AMI deployment is approved, the AG requests the following limitations:

  • Surgical deployment – provided only when requested by customers who are willing to pay for them
  • Replacement deployment – as AMR meters die, replace them with AMI meters
  • Prudence review – cost recovery via a base rate case and only after CL&P demonstrates the costs were prudent

It is unfortunate the AG does not see that a couple of the limits he is seeking to place on the program would erode and further minimize the benefits of AMI deployment. Operational savings are optimized when there is full deployment. CL&P submitted a cost-benefit analysis. Here are just some of the benefits:

  • Peak load reduction of 125 megawatts annually. This is sizable enough to forgo running a small power plant. Numerous additional benefits stem from this fact alone. When you forgo a power plant, you eliminate all the expense, environmental impact, energy , etc. that goes along with running the plant
  • Total energy reduction of 190 million kWh per year, saving enough energy to power 20,000 homes
  • Carbon emission reduction of 100,000 per year, giving Connecticut air the positive equivalent of 13,000 less cars on the road
  • Two percent reduction in storm outage duration

These benefits will be further optimized with full deployment, as that sets the stage for the best customer education and engagement process.

In a surprising move, DP&L asked the Public Utility Commission of Ohio to be allowed to withdraw its Advanced Metering Infrastructure and Smart Grid business cases that were approved in June 2009. Reserving the right to revisit AMI and Smart Grid deployment in the future, DP&L cited factors beyond its reasonable control in the memo filed with the PUCO. Not getting a slice of the stimulus funds pie that its fellow Buckeye peers received – $75 million for AEP, $200 million for Duke Energy and $57 million for FirstEnergy – was a contributing factor.  These other utilities will continue their respective smart meter deployments. The Commission granted DP&L’s motion on January 5, 2011.

DP&L’s caution is not unfounded given the ongoing drama facing PG&E and its smart meter program, which is still reeling from a revolt by a segment of the public wary over possible privacy intrusions and misplaced fears of physical harm. Xcel, the pioneer of SmartGridCity in Boulder, Colorado, also was dealt a setback recently by the Colorado Public Utilities Commission that temporarily slashed its smart grid cost recovery slashed its smart grid cost recovery by roughly a third. And in Westerville, Ohio, the city cancelled its smart meter plan last year amid fears by skeptics that smart meters will erode privacy. However, the city council this week approved the installation of smart meters for businesses and some schools.

In an order that took many by surprise, the Colorado Public Utilities Commission slashed $14.8 million in cost recovery from the Public Service Company of Colorado’s (“PSC”) smart grid pilot. PSC is a subsidiary of the trailblazer Xcel Energy. This reduction is in spite of a settlement where parties agreed to, and ALJ G. Harris Adams recommended approval of, a recovery of $44.5 million for the much-heralded pilot project called “SmartGridCity” (SGC) in Boulder, Colorado.  

In its written decision issued last week, the Commission signaled its unease over the lack of a detailed, strategic plan for the use of SGC investment and whether the projected benefits would be actualized. However, the $14.8 million is not completely lost. PSC can recover the costs upon demonstrating “the credible promise of consumer and utility benefits” and “the ability of customers to make practical use of SGC on their side of the meter through in-home devices.” 

The SGC, which began in 2008 for 24,000 customers and includes plugs for electric vehicles, smart substations and feeder automation enabled by fiber-optic broadband internet, was projected to cost Colorado ratepayers $15.3 million. But the cost shot up to $27.9 million in early 2009, and by 2010 when the estimate nearly tripled to $44.5 million, public criticism mounted quickly and loudly.

Xcel and the Colorado Governor’s Energy Office note that SmartGridCity has already produced clear benefits, such as preventing outages, but many of those benefits have yet to be assigned dollar figures.

Triple cost-overruns would raise eyebrows in any business venture. But in grasping this cost-mismanagement episode, one should take into account the pioneering nature of this pilot project. Industry analysts note that a key goal of this pilot project is acquiring knowledge for future applications, not just guaranteed savings. 

“It’s going to be easier for other people to do cost-benefit analyses because of the data [PSC] gathered,” – Katherine Hamilton, GridWise Alliance

When you consider that the project began before smart grid initiatives became a national priority, I wonder whether Xcel should be given some slack for being a Smart Grid pioneer.

 

OG&E filed an application on December 17,2010 with the Arkansas Public Service Commission seeking approval to recover costs for the installation of smart meters and related smart grid technology. OG&E is hoping that when armed knowledge and information about the real time price of energy, customers will make energy-use decisions that shift demand away from hours when electricity costs are at their highest, to lower-cost times of day, saving money on their monthly bills and helping OG&E delay the need for the costly addition of more generating capacity. This would be a win/win as OG&E would reach its Goal 2020. “This technology and the efficiencies it brings are integral components in our goal to reach the year 2020 without adding fossil-fueled electric generation,” said Howard Motley, vice president of regulatory affairs.

If the Commission approves the plan filed today, OG&E expects to begin installation of approximately 70,000 smart meters and associated smart technology in its western Arkansas service area in the second half of 2011. Installation of the technology would increase the average residential customer’s electric bill by $1.64 per month. The filing also identifies the portion of a $130 million federal stimulus grant that OG&E will utilize to help offset costs to Arkansas customers. 

The smart technology OG&E is proposing uses the networking capabilities of the new meters and a secure wireless network to allow the company to read meters remotely, as well as start and stop service. Other smart grid devices will add greater automation to the company’s electricity distribution system, helping to reduce the frequency and duration of outages. The full roll out of smart technology, which includes new meters, in-home technology, a wide area network (WAN) and distribution system automation, is expected to be completed around 2017.

It does not take long to understand that everyone: utility, customers and society benefit from a smarter grid. Let’s examine one feature of  the smart meter – the ability to do remote disconnect/reconnect will save both OG&E and its customers millions of dollars. The company should see a decline in collection related write-offs in addition to the efficiencies from being able to turn service on or off at the flip of a switch.  This will yield less fleet, less gas, less emissions and a greener environment and greener wallets.

BGE took the political high road and decided to move forward with a modified version of its smart grid plan despite not receiving cost recovery via a surcharge tracker. In a news release the day it filed its modified proposal, BGE president and chief executive officer, Kenneth W. DeFontes expressed disappointment over the Commission’s June 21,2010 order but remained hopeful the revised plan would get approved; allowing the company to get on with the business of enhancing reliability, move toward meeting its EmPOWER Maryland goal to reduce energy consumption by 15 percent by 2015 and put to use the $200 million stimulus grant the company was in jeopardy of losing. 

Although the revised plan was approved and the Maryland PSC stressed its decision should not be viewed as a no confidence vote in smart grid technology, the Commission also remained unpersuaded from its original position on cost recovery.  The 51 page decision states:

…we will not authorize cost recovery for any approved ‘smart grid’ or AMI project through a surcharge.” We reached that conclusion because the proposed AMI deployment “would represent a large, but classic investment in BGEs distribution infrastructure,” precisely the kind of investment that BGE has recovered through traditional ratemaking for a century. We are not persuaded to deviate from these principles by BGEs arguments regarding the magnitude of the AMI investment or the possibility of negative reactions from credit rating agencies. Pg.32

When announcing its intent to proceed with smart grid implementation, BGE highlighted the Commission’s support of prudently incurred cost recovery rather than “unfair, post hoc nickling-and diming.”  This was no doubt a shout out to the victorious AARP and the OCP!

On June 21, 2010, to the surprise of many, the Maryland Public Service Commission (“MPSC” or “Commission”) denied Baltimore Gas and Electric Company’s (“BGE”) Application to Deploy a Smart Grid Initiative (“Proposal”).  Stating, “Although we share BGE’s (and others’) hopes, and even enthusiasm, for the long-run potential and importance of the infrastructure upgrades known colloquially as the “smart grid,” we find the business case for this Proposal untenable.”   This decision jeopardizes approximately $136 million BGE was awarded from the U.S. Department of Energy (“DOE”) pursuant to the American Recovery and Reinvestment Act (“ARRA”) for smart grid funding.  The total price tag for BGE’s filed plan was $835 million.  The Commission stated that BGE should fairly allocate between itself and its customers the risk of the smart grid journey.  
In denying the Proposal, the Commission goes on to discuss concerns it has about exposing customers to unproven technology that could quickly become obsolete due to evolving Advanced Metering Infrastructure (“AMI”) technology standards.  The decision states BGE planned to install the ZigBee chip in its smart meters.  Currently, ZigBee is the dominant technology in the AMI market.  However, at this time, no appliance manufacturer has adopted ZigBee technology.  In order to provide customers with the option of deriving the full benefits of the smart meters that BGE hoped to install, the meters should be able to communicate with smart appliances when they are created.  The following quote from the decision highlights the Maryland Commission’s stance that it will not expose its ratepayers to the risks of being an early adopter:
“The field of modern technology is replete with examples of innovations once considered the leaders into a new era that were never widely adopted. All the federal funding in the world would not have made Sony’s Betamax a wise investment, for example. Those who invest in new technology as it becomes available often find themselves re-investing much sooner than they anticipated.”
This view by the Maryland Commission begs a few questions: “What if all the states took that stance?  Would the smart grid and all its technological moving parts have an opportunity to mature and provide BGE’s ratepayers and the rest of us all the benefits of a modern electrical grid? Since smart meters will ultimately teach customers how to use less of BGE’s core product, electricity, doesn’t the very filing of the Proposal qualify as an investment by BGE?

On June 21, 2010, to the surprise of many, the Maryland Public Service Commission (“MPSC” or “Commission”) denied Baltimore Gas and Electric Company’s (“BGE”) Application to Deploy a Smart Grid Initiative (“Proposal”).  Stating, “Although we share BGE’s (and others’) hopes, and even enthusiasm, for the long-run potential and importance of the infrastructure upgrades known colloquially as the “smart grid,” we find the business case for this Proposal untenable.”  This decision jeopardizes approximately $136 million BGE was awarded from the Department of Energy (pdf) pursuant to the American Recovery and Reinvestment Act (“ARRA”) for smart grid funding.  The total price tag for BGE’s filed plan was $835 million.  The Commission stated that BGE should fairly allocate between itself and its customers the risk of the smart grid journey.  

In denying the Proposal, the Commission goes on to discuss concerns it has about exposing customers to unproven technology that could quickly become obsolete due to evolving Advanced Metering Infrastructure (“AMI”) technology standards.  The decision states BGE planned to install the ZigBee chip in its smart meters.  Currently, ZigBee is the dominant technology in the AMI market.  However, at this time, no appliance manufacturer has adopted ZigBee technology.  In order to provide customers with the option of deriving the full benefits of the smart meters that BGE hoped to install, the meters should be able to communicate with smart appliances when they are created.  The following quote from the decision highlights the Maryland Commission’s stance that it will not expose its ratepayers to the risks of being an early adopter:

The field of modern technology is replete with examples of innovations once considered the leaders into a new era that were never widely adopted. All the federal funding in the world would not have made Sony’s Betamax a wise investment, for example. Those who invest in new technology as it becomes available often find themselves re-investing much sooner than they anticipated.

This view by the Maryland Commission begs a few questions: “What if all the states took that stance?  Would the smart grid and all its technological moving parts have an opportunity to mature and provide BGE’s ratepayers and the rest of us all the benefits of a modern electrical grid? Since smart meters will ultimately teach customers how to use less of BGE’s core product, electricity, doesn’t the very filing of the Proposal qualify as an investment by BGE?