Emergency Preparedness and Operations Reliability Standards

Most of the world was stunned to hear that Hurricane Maria left the island of Puerto Rico completely without electricity. When Hurricane Irma hit Florida, utilities across the United States sent thousands of linemen and other utility workers to assist Florida utilities. The picture below highlights a portion of the visiting crews ready to provide help.    

Photo credit: Eversource

Upon hearing of an island-wide blackout, I thought, “Crews drove across the United States to Florida. The effort required to send utility trucks and other equipment to Puerto Rico will be epic. Ferries will be in high demand.” And sadly, even before the island was hit by Hurricane Maria, the Puerto Rico Electric Power Authority had already filed for bankruptcy in July 2017. The Authority stated then it needed more than $4 billion to overhaul its outdated power plants and reduce its heavy reliance on imported oil. In 2016, 47% of Puerto Rico’s electricity came from petroleum, 34% from natural gas, 17% from coal and 2% from renewable energy. Most American utilities rely on natural gas, coal, nuclear and renewable resources. Fuel source aside, how does a utility recover from an island-wide outage?

In the U.S., the Federal Energy Regulatory Commission (FERC) has rules to address this very issue. And on September 20, 2017 the FERC issued a Notice of Proposed Rulemaking (NOPR) regarding revised Emergency Preparedness and Operations (EOP) Reliability Standards (please note that the document is large and may take some time to load) submitted by the North American Electric Reliability Corporation (NERC), intended to:

  • provide accurate reporting of events to NERC’s event analysis group to analyze the impact on the reliability of the bulk electric system (EOP-004-4);
  • delineate the roles and responsibilities of entities that support system restoration from blackstart resources that generate power without the support of the grid (EOP-005-3);
  • clarify the procedures and coordination requirements for reliability coordinator personnel to execute system restoration processes (EOP-006-3); and
  • refine the required elements of an operating plan used to continue reliable operations of the bulk electric system if that primary control functionality is lost (EOP-008-2). 

I appreciate the work done by regulators and utilities to provide a reliable and resilient electric grid. Comments on the NOPR are due 60 days after publication in the Federal Register

National Grid recently received the Massachusetts Department of Public Utilities’ approval to begin a two year comprehensive smart grid pilot. An important element of the pilot is the company’s focus on customer outreach and education. Cited as its “listen, test, and learn” approach, National Grid will use a variety of different communication channels, both traditional and community-based, to attempt to elicit customer behavior changes and gain valuable insights regarding options for larger deployment of smart grid tools and technologies.

A noted feature of the outreach plan will be a Sustainability Hub located near Clark University.

Leveraging college student interns through the co-op program and partnerships with vendors and community stakeholders, the Sustainability Hub will provide hands-on community access to smart grid technology and information regarding pricing structures offered in the pilot.

National Grid intends to evaluate:

  1. the effects of each media channel, such as print, web, mobile, electronic, social, and broadcast media;
  2. the number of attempts to reach each customer;
  3. the timing of messaging;
  4. the effects of targeted messaging (e.g., environmental, cost consciousness);
  5. the effect of messaging through in-home devices;
  6. customer satisfaction, interest, and behavior; and
  7. the effectiveness of the critical peak event notices.

In approving the plan, the MDPU found a two-year pilot could help access “customer fatigue” and allow for more robust results and analysis, as well as provide useful insight to help inform future smart grid development.

Join speaker Linda R. Evers for a Webinar focused on the public relations aspects of the smart meter debate. Taking place July 31, “Smart Meter Best Practices: Public Relations and Managing Expectations” is an informational webinar geared toward utility companies and will outline how an effective communications plan can prepare utility companies for smart meter issues potentially raised by consumers.

Read the brochure for registration and other information.

Ms. Evers is one of the featured presenters and, using smart meter cases and consumer concerns from across the country, will walk participants through various issues that have arisen when deploying smart meter technology and how to manage those issues.

Through a recent press release, the Illinois Commerce Commission stated that Ameren Illinois’ AMI plan could not be approved because it would have to rely on either including gas meters or a compliance period longer than ten years, neither of which is allowed in the statute. Additionally, the Commission determined that the cost-benefit analysis presented by the company relied on incomplete or speculative calculations, referring to the plan as

vague and incomplete and bordered on not being a plan at all, but rather more of a general statement of intention to install smart meters in some parts of its service territory.

ICC Chairman Doug Scott said, “When and where the company meets its legal obligation it provided scant information. I am troubled by the inadequacy of the plan.” Commissioner John Colgan noted that while there are benefits to customers from a smart grid system, Ameren witnesses did not demonstrate any, leaving commissioners nothing to work with or modify. “I wish we had better information,” he said. 

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.

Despite having approved Central Maine Power’s (CMP’s) Automated Metering Infrastructure (AMI) plan in February 2010 as a program designed to “improve customer service, enhance storm restoration efforts, reduce utility operational costs, save ratepayer and utility costs, and ultimately provide customers with necessary tools to use electricity more efficiently,” on January 4, 2011, the Maine PUC voted unanimously to open an investigation at the request of complainants citing health concerns. (Docket Numbers 2010-345, and 2010-389). The Commission states the investigation will examine:

  • the possibility of local opt-outs to the program already being implemented and installed by CMP;
  • the possible effect of such an opt-out on the original federal Department of Energy (DOE) grant which helped fund approximately half the cost of the program;
  • the availability of hard-wire alternatives from CMP;
  • cost implications of any alternatives; and
  • what impact the alternatives would have on the smart grid program’s goals. 

Attorney Beth George of Scarborough, MI, is just one of several CMP customers requesting an investigation. Her letter to the Commission expressed concern about a few of her neighbors having “some type of heart failure” within weeks of each other. Additionally, the Scarborough Town Council passed a resolution requesting CMP to delay the installation of the “so called smart meters.” The Council is asking the Commission to give customers the ability to opt out of having the wireless smart meters installed. Several state representatives weighed in requesting an investigation as well.

I wonder if any of the complainants have cell phones, use Wi-Fi for their home internet connections or use cordless phones? Will CMP lower its carbon footprint by sending a meter reader to read three meters on Cleveland Circle and two meters on Hampton Circle? Obviously efficiencies will be lost. And what about the software and other technology issues? Will CMP have to maintain dual billing systems? There is a strong possibility these options will take an expensive plan and make it cost prohibitive.


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.