Utilities Dig Out After Irene

By Jeff Postelwait, online editor

As President Barack Obama warned that full recovery from Hurricane Irene’s after-effects would take time, utilities, field crews and plant operators worked to restore power to East Coast residents.

On Aug. 29, some 5.5 million homes and business were still without power from North Carolina to Maine, the U.S. Department of Energy estimated, and utilities said it could take days to restore electricity in more accessible areas, or up to weeks in the hardest-hit regions.

As many as 6 million customers were cut off from electricity following Hurricane Irene.

At least 21 people died in the U.S. in addition to three who died in the Dominican Republic and one in Puerto Rico when the storm was still in the Caribbean.

Hurricane Irene became a tropical storm somewhere near the U.S.-Canadian border by late Aug. 28, as its wind speeds slowed to 50 miles per hour.

Rhode Island reportedly had the largest percentage of its population cut off from power; about 275,000 people were affected by the blackouts in that state.

New York, New Jersey, Connecticut and Virginia, where the outages were greatest in number, each had more than 600,000 customers without power by August 29.

New York had some 939,000 people living in the dark, and about 4,000 of those had their power restored by that same day. Many utilities with service areas in Irene’s path estimated that power restoration could take a full week or longer.

FirstEnergy reported thousands of downed power lines in the Pennsylvania, Maryland and New Jersey areas after Irene. FirstEnergy’s main utilities, Jersey Central Power and Light and Metropolitan Edison, reported more than 850,000 outage-struck consumers.

The PJM Interconnection worked with its constituent companies to restore power to some two million customers dealing with blackouts in the PJM service territory. At the storm’s height, an estimated three million customers were without power, primarily in Virginia, North Carolina, the District of Columbia, Maryland, Delaware, New Jersey and Pennsylvania.

For more on outage recovery, see the feature on Page 40.

Navy Commands grid charge

By Terry Kern, American Systems

The Department of Defense (DoD) is the largest power consumer within the U.S. government. Soaring energy costs and extended military commitments abroad make energy resource optimization and management a strategic issue for the DoD. The Department of the Navy (DoN) leads the energy conservation charge by committing more than $100 million in American Recovery and Reinvestment Act (ARRA) funding to its growing advanced metering infrastructure (AMI) program. The DoN is developing and deploying technologies that help the military evaluate, understand and optimize energy resource utilization.

DoN awarded thirteen task orders to upgrade AMI infrastructure at military bases in the Southwest and along the coast of North Carolina to American Systems, a systems integrator headquartered in Chantilly, Va.

The DoN wants to integrate utility meters with government-owned and operated data acquisition systems (DAS), software, servers and workstations. All collected data will reside in local repositories, will be managed at a regional level and will be exported in formats compatible for roll-up into global repositories. Transactions between end devices and system components will be enabled by two-way communication that accommodates meter configuration downloads, on-demand data collection, system condition queries, secure control over functionality and off-net access.

In a full AMI integration, existing network infrastructures, supervisory control and data acquisition (SCADA) and AMI solutions are managed and controlled from a single administration system. AMI infrastructures provide communications that extend existing network capabilities and conform to all relevant technical guidance.

The DoN’s new AMI infrastructures leverage existing direct digital control (DDC), SCADA and/or building automation. The combined infrastructure is further integrated with other existing premise systems and networks that provide for physical security via fire and alarm systems, life safety systems and emergency response operations.

Terry Kern is American Systems’ business leader for energy IT and systems integration within the Network Engineering Management Services Directorate.

Illinois Governor Vetoes Smart Grid Bill

By Kathleen Davis, senior editor

In September, Illinois Governor Pat Quinn vetoed a state bill allowing Commonwealth Edison (ComEd) to recoup smart grid upgrade costs from consumers.

Quinn had been vocal about vetoing the bill, and he followed through.

“It may be a dream come true for Commonwealth Edison,” said Quinn at a news conference to announce his decision. “But it’s a nightmare for Illinois consumers.”

Declaring that he was “protecting Illinois consumers from massive electric rate hikes,” Quinn shot down Senate Bill (SB) 1652, which raised rates in increments over the next 10 years to pay for system upgrades, resulting in a $3 billion cash pool.

Quinn said more than a million residents and businesses experienced power outages this summer and stated that, with the bill, utilities wanted to “eliminate accountability.”

“I will not support a bill that contains sweetheart deals for big utilities, which could leave struggling consumers to pick up the tab for costs such as lobbying fees and executive bonuses,” he said.

“This bill would have been devastating for Illinois consumers,” Illinois Attorney General Lisa Madigan said at the same Sept. 12 news conference. “At a time when people are already struggling to pay their bills, the utilities want to make an end run around the regulatory process and stick consumers with huge annual rate increases for unproven technology.”

The veto action was supported by AARP, the Citizens Utility Board, Citizen Action/Illinois and the Environmental Law and Policy Center, according to Quinn.

ComEd issued a statement following the veto expressing disappointment and vowing to show how the bill provides benefits to Illinois. The statement pointed out that SB 1652 went through 40 revisions to cater to consumer and regulatory input.

“Despite the rhetoric of the legislation opponents, SB 1652 does not guarantee profits, will not result in automatic rates increases and does not strip the authority of the Illinois Commerce Commission,” the statement said.

A few Illinois legislators, including State Reps. Mike Jacobs and Kevin McCarthy, spoke to local newspapers about overriding the bill when state lawmakers returned in October. As of press time for this issue, no override of SB 1652 materialized.

Smart Grid Conversations

By Diganta Baishya, Redpine Signals

Smart grid technology creates an intelligent system capable of regulating supply and demand of electricity. The strength of the system lies in its self-regulatory capabilities to normalize power consumption; this is achieved through different types of digital “conversation.”

  • Conversations on load balancing. Utilities need to meet peak demand. Equipment failure due to overload conditions and the need for capacity increases hinder services delivered by utility companies. Hence, peak load balancing is one of the main objectives of a smart grid that can talk.
  • Conversations on analytics. The power grid is a dynamic system with complex patterns of consumption in the course of a day. Analytical pattern information is invaluable in pre-empting grid failures and planning capacity and expansion. Data analysis can determine important correlations between consumption and population or industrial development and economic output. These conversations can identify inefficiency sources and waste.
  • Smart conversations. The smart grid would not be smart if devices couldn’t communicate. A washing machine can be told to run at low-demand times of the day, leading to lower charges. A thermostat can be set a few degrees higher to regulate power consumption when energy is expensive. The logic applies to home and enterprise devices alike. For such purposes, devices need to understand the state of the real-time load at the grid, and the grid needs to communicate the information, even control the end devices.
  • Smart Wi-Fi conversations. Wi-Fi is increasingly becoming a single seamless standard for device interconnectivity for all purposes. It’s no longer enough to connect devices with a smart meter. Today’s smartphones and tablet PCs control and monitor home appliances from anywhere in the world using the Internet. Wi-Fi inherently provides IP connectivity. The scalability of connectivity is unlimited in this architecture. Additionally, Wi-Fi Direct, the latest Wi-Fi technology, enables Wi-Fi-enabled devices to communicate with one another without an access point. With Wi-Fi, every single home, enterprise or industrial device could have an IP address and become an integral part of the Internet. Smart grid is a subset of this large network, using the same infrastructure and technology.


Diganta Baishya is Redpine Signals’ product manager.

Study Finds Meter Benefits Exceed Costs

By Lisa Wood, Institute for Electric Efficiency

The potential of smart meters and advanced metering infrastructure (AMI) is well understood: enabling remote meter reading, better outage detection, dynamic pricing programs, advanced home energy management technology and basic bill-to-date information. AMI can improve reliability and produce money and energy savings for utilities and customers.

How does the potential of AMI compare to its costs? The Institute for Electric Efficiency (IEE), along with The Brattle Group and To The Point, produced a quantifying framework on AMI in the paper “The Costs and Benefits of Smart Meters for Residential Customers.” The paper’s findings come from a wide variety of perspectives across a range of electric utility and customer types. The framework is general enough for utilities and regulators to adapt and conduct their own analyses.

In looking at the benefits of AMI, they identified three categories:

  • Operational. AMI enables remote meter reading, thereby avoiding meter reading costs. It allows a utility to quickly and remotely meet customer requests for service connections and disconnections, and it permits better outage detection and recovery to a utility’s entire customer base at a lower overall cost.
  • Customer. By giving customers information about their energy usage and/or electricity price signals, AMI can help them gain better control over their electricity usage, which can lead to lower bills as well as help to mitigate cost increases.
  • Societal. AMI’s demand response and direct load control capabilities enable a utility to reduce peak demand. Additionally, it applies downward pressure on energy prices in spot markets, offsetting the need for new generation and transmission and distribution (T&D) capacity. This could potentially lower carbon emissions through integration of cleaner distributed generation and household usage reductions as well.

In deriving cost assumptions, the IEE relied on AMI business cases and equipment manufacturers’ prices, as well as projections and other sources. The framework included different utility and customer types. The paper identified areas that influence the business case for smart meters, including current generation mix, renewable energy portfolios, regulatory environments, energy prices and a utility’s emphasis on efficiency and conservation.

IEE factored in how likely customers were to be engaged in a utility’s energy programs, how actively those customers would manage energy use and customers’ cost consciousness. Assuming a service area of one million households, IEE found that the total AMI cost for a utility—net present value over a 20-year period—will vary from a low of $198 million to a high of $272 million (with associated home energy management technologies).

AMI investment will produce operational savings between $77 million and $208 million, and customer-driven savings between $100 million and $150 million. The net benefits from investing in AMI ranged between $21 million and $64 million.

Analysis revealed that accelerating electric vehicle (EV) adoption is the strategy with greatest financial benefit to utilities and customers. Households that have EVs represented only 1.25 percent to 1.5 percent (12,500-15,000) of the hypothetical one million customers in a service territory. Those households, however, created a disproportionately high share of consumer-driven savings, indicating that even modest EV increases will have a beneficial impact.

Lisa Wood is IEE’s executive director. The IEE white paper is available for download at http://edisonfoundation.net/IEE

Human Error Leaves Millions in the Dark

By Kathleen Davis, senior editor, and Jeff Postelwait, online editor

About 5 million people in Southern California, Arizona and Mexico were enveloped in a power outage on Sept. 8 with outage times up to 12 hours in places.

The outage was attributed to human error, according to reports, and was triggered by a utility employee working on a substation in Arizona. The blackout caused traffic jams on California freeways and disabled water services in San Diego and Tijuana.

San Diego Gas and Electric (SDG&E) said in a tweet that 1.4 million electricity customers in the San Diego service area were without power. Another 3.5 million in the Baja California area were also in a blackout. Yuma, Ariz., reported outages for about 50,000 people.

Such an outage has never before happened to the San Diego service area, according to SDG&E.

The cascading power failure was caused by a botched maintenance procedure in Arizona that resulted in the shutdown of a transmission line supplying power to the San Diego area. This, in turn, interrupted the power flow from California’s 2,200 MW San Onofre nuclear power plant, according to SDG&E.

Arizona Public Service (APS), the utility that covers the interconnected transmission bringing power into San Diego, said both human and system failure were to blame for the outages which were triggered on Sept. 8 at 3:30 p.m. when the North Gila-Hassayampa 500 kV transmission line shut down.

An employee working at the North Gila substation northeast of Yuma created the cascading blackout when protection protocols that should have isolated the outage failed.

SDG&E restored power at 3:25 a.m. on Sept. 9.

“Restoring power in the aftermath of the loss of the entire local grid serving San Diego and southern Orange counties was a monumental task and the independent system operator, the region’s power plant managers and our employees really rose to the challenge,” said David Geier, vice president of electric operations for SDG&E, in a statement released by the utility.

Geier also said that restoration had left the local grid “fragile” and asked for conservation for a few extra days.

Lessons from the Blackout

After the San Diego blackout of Sept. 8, Senior Editor Kathleen Davis spoke to Frost & Sullivan’s Energy & Power Systems Principal Consultant Farah Saeed about perceptions of and lessons learned from the crisis.

KD: What did the San Diego blackout teach the energy consumer about the power industry?

FS: Most consumers tend to take electricity for granted. A survey that Frost & Sullivan conducted showed that residential consumers appear unconcerned about the availability of electricity. Roughly four out of 10 never think about the availability of electricity in their area, and only 6 percent think that the availability of electricity is an actual problem. This scenario might change in light what happened in San Diego, although I don’t expect a major movement towards off-grid systems because of this particular incident.

KD: What about communication? How would you rate SDG&E’s work with the public during this blackout?

FS: In general San Diego Gas & Electric has a good reputation for customer service and is considered a thought leader for smart grid implementation.

KD: What should the power industry learn from that blackout? Major lessons?

FS: While I am not involved in this investigation, my understanding is that this incident is a rather rare coincidence that was caused by a single manual error by a single worker who replaced a capacitor without ensuring proper grounding. I don’t think a smart grid could necessarily have prevented this particular incident because some tasks still must be done manually. However, the escalation of this issue could have been prevented through better planning.

KD: Were there any positives from the blackout (from a technology viewpoint)?

FS: Closer evaluation of decentralized grid systems, such microgrids, might come from this blackout.

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The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at Jennifer.Runyon@ClarionEvents.com.

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