Navigant Research Blog

Research Shows Prepay Pays Off

— April 1, 2013

Although utility prepayment programs are not yet a major market in the United States, which lags behind many other countries that have offered such schemes for decades, Navigant Research has forecast that the North American electric prepaid metering market will grow rapidly over the next several years, expanding at a robust compound annual rate of about 23% from 2013 to 2018.

The Salt River Project (SRP) in Phoenix, Arizona, a prominent trailblazer of prepay, has operated prepaid electric services under the M-Power brand for 20 years. Today, about 126,800 residents are enrolled in SRP’s prepay plan, more than 12% of the residences that it serves.  M-Power customers have consistently demonstrated a high level of customer satisfaction in surveys by the utility, but most noteworthy has been their overall reduction in electricity use: around 12%.  Despite SRP’s results and similar finding by other utilities, establishing a reliable and statistically proven link between prepay and energy usage is still difficult.  However, a recent study led by consulting firm DEFG shows a strong positive correlation between prepayment of energy bills and conservation behavior.

Impressive Savings

Using consumer data from Oklahoma Electric Cooperative (OEC), which launched prepay services in 2006, to compare post-pay and pre-pay customers, the study concludes that participants in prepaid plans on the average reduce their energy usage by 11% (about 1,690 kilowatt-hours per year for an OEC customer) ‑ very similar to SRP’s findings. Compared to other energy efficiency measures ‑ and considering the relatively low cost of implementation, from a utility standpoint, and the ease of adoption for customers (there’s no need to purchase a special energy efficiency device, for instance) – this is an impressive figure.  Since the average monthly bill for OEC’s customers is $146, an 11% energy saving translates into a $192-per-year reduction on the customer’s utility bill.

The energy use reductions can be attributed to several factors, including increased awareness of when and how electricity is consumed.  The study also demonstrates that regular (even daily) communication from the utility to the customer that provides actionable information (usage tied to dollars and cents) changes consumption behavior.

This data provides strong evidence that electric prepayment is a winning proposition for both utilities and consumers, and it should convince more utilities to offer prepay options.  What’s more, according to a recent national survey of 1,000 individuals, 38% said that they were interested in prepaid electric services.  This shift is long overdue.

 

With Consert Acquisition, Toshiba Targets U.S. Utilities

— February 20, 2013

Source: WikimediaJapanese electronics giant Toshiba has assembled a portfolio of solutions that positions it well for two of the hottest smart grid opportunities available right now: demand response (DR) and microgrids.  Now, if it can figure out a way to leverage the technology of recent acquisitions into a coherent integrated package, the company could make major inroads into new geographic markets, especially the United States.

The announced purchase last week of Consert is a case in point.  Consert’s current portfolio is minuscule when compared to other DR aggregators, such as EnerNOC (8,500 MW) and Comverge (5,500 MW), but the company focuses on providing the highest value DR from the most difficult places: the residential market.  The firm’s flagship project is a 250 MW “virtual peaking plant” for CSP, the municipal utility that serves San Antonio, which could achieve full build-out within the next 3 to 4 years.

General Electric, Constellation, and Qualcomm have all invested in Consert.  Its “software as a service” business model is gaining traction within smart grid software providers, too.  The company has been focusing on public power utilities – its low-cost solution is not the ideal fit for investor-owned utilities.

Toshiba apparently plans to marry Consert’s real-time DR capability with the data analytics enabled by its May 2011 acquisition of Swiss technology supplier Landis+Gyr (L+G).  L+G  is  the leading supplier of electrical meters in the world (as well as North America).  Think of the possibilities if one could link up L+G smart meters with Consert’s real-time, two-way communication down to each device-level offering? Toshiba might actually provide some of the elusive value for both utility and consumer that has escaped so many smart meter deployments in the United States.

Along with this DR capability from Consert, one must also consider the technology expertise of Toshiba itself.  Toshiba’s unique advantage over other grid infrastructure companies may be its ability to link home energy management (HEM) systems, as well as commercial smart building technology, with optimized microgrid functionality.  Toshiba already has deployed a 4 MW solar and wind microgrid on Japan’s Miyako Island.  The Japanese company is also providing DC/AC power conditioners and smart inverters with widespread applications in remote microgrids, as well as its rechargeable battery known as SCiB.

Toshiba was once so bullish on the overall smart grid market that it reported that it hoped to reach over $11 billion in revenue from this market by 2015, with over $1 billion in the United States alone.  The only way that’s going to happen is to integrate the company’s smart meter, microgrid controls, and DR capability in the United States, and make the business case for boosting reliability and revenues through its unique portfolio of products in the world’s leading markets for both DR and microgrids.

 

In Cyber Security, It’s the Whole Picture That Matters

— January 29, 2013

Source: Patent Pending BlogThe story goes that a group of business people were stranded on a desert island with a bountiful supply of canned and therefore imperishable food, but no way to open the cans.  As the group struggled to find a solution the lone economist in the group piped up, “Assume a can opener…”

Sometimes it seems that’s how we approach industrial control systems (ICS) security.   “Assume a secure perimeter…”  It’s not fair to expect any single product or any single vendor to provide complete security for ICS networks, and yet we seem stuck in a world of point-solution purchases and security without any overriding architecture.   It’s as if we’re saying, “If I can just get me some [insert technology of the week], then I’ll be secure.”

Barely 3 weeks into the new year, I have already had wonderful briefings from companies whose products lock down privileged IDs, ensure clean networks by detecting attacks at network chokepoints, heuristically identify attacks though behavior analysis rather than signatures, protect control networks from the lawless jungle that is enterprise IT, and so on.

All of these approaches are good, and all of them are necessary.   But in isolation, none protects an ICS network.   Cyber security still begins with risk assessment, not product purchase.  Every utility is a business, and every business is unique.   So before you go ask for this year’s cyber security budget, do a little planning.   Skip the shortcuts.

Call for Help

To the utilities that have a shopping list of security products but no overarching plan how to use them: You might be amazed how much you can save in deployment and ongoing maintenance with just a little thought.   Over the years I’ve seen countless companies purchase a less expensive product without planning how it would be supported.   A bargain is no bargain when it requires an excess staff of 10 full-time employees for 10 years to support it.

To vendors happy to show up at a utility and sell only their product: think about your customer as a business, not an account.   If you don’t see enterprise security planning going in, bring in some help.  Maybe that help is a systems integrator, maybe it’s just a single security assessor.  Maybe it’s collaboration with other cyber security vendors or even – gasp! – a competitor.  No matter what, understand the whole problem, not just the problem that your product will fix.

There is some cause for encouragement.   Compared to 2 years ago, vendors are much more likely now to tell me that they are part of a full cyber security solution.  Utilities have become much more methodical in their approach to cyber security – especially as OT teams have become savvy and made their reliability requirements part of cyber security projects.

 

Duke’s Schneider Aims for Grid Resilience

— January 28, 2013

Source: Duke EnergyAccording to The Huffington Post, more than 660,000 people lost power in Connecticut during Tropical Cyclone Sandy.  A spokesperson at Connecticut Light and Power reported that 90% of these outages were caused by falling trees that downed power lines. Others spoke of heavier damage, such as flooded substations as the root cause.

Utility distribution operators and outage crews put in a tremendous effort to repair damages and restore power.  In the aftermath, utilities are doubling down on grid resiliency to be better prepared for next time.  Smart utilities are investing in looped power lines peppered with intelligent devices in an effort to reduce the outage impact of downed power lines and other faults.  By “looped and intelligent,” I mean power systems that have automated redundancy, enabling faster restoration.  System Average Interruption Frequency Index (SAIFI) is the IEEE metric for the number of sustained interruptions per customer over a year.   The distinction between a shorter and a sustained outage varies from state to state but is most often 5 minutes, meaning a sustained outage is greater than 5 minutes.

In a recent interview, Don Schneider, who oversees grid modernization projects at Duke Energy, told me that, “As part of Duke Energy’s overall Grid Modernization program, we are deploying grid automation devices that help improve SAIFI.”

When dual- or multi-sourced lines with grid automation devices are in place, there will be significant reductions in affected customers during storms that cause heavier damage over a small area (for example one faulted substation in looped circuits), or moderate to extensive damage over a large area (for example a half a dozen randomly distributed faulted lines per dozens of substations, i.e., enough transformer capacity to reconfigure sourcing to some or all un-faulted sections).

“Self-healing teams, by means of two-way communication to fault-interrupting and switching devices, can locate a faulted section of line, isolate that section of line, and restore power from another source,” says Schneider.

Self-Healing Helps Many

He also describes how the investment in self-healing is creating returns for Duke customers in Ohio.  “In our currently active Ohio Grid Modernization project we have installed 24 self-healing teams over the past 4 years.   From these self-healing teams we have experienced 20 operations that have resulted in 30,000 customers that have avoided a sustained outage,” says Schneider.

Based on EPRI research, it’s reasonably conservative to assume that an avoided outage is worth $2.50 to residential customers and $250 to small commercial customers. With a typical 90:10 ratio between these two customer classes that comes out to an average value of $25 per outage. Using this conservative assumption, it’s fair to say that self-healing in the currently active deployment has likely created $750,000 in satisfaction value to Duke Ohio customers.

While self-healing systems can do little when power systems are faulted at the majority of sources within a service territory, it’s interesting to look into cases such as in Connecticut, where 90% of outages were reportedly line faults caused by trees.  Assuming most of the substations were still standing, and if all lines were modernized, the utility could quickly restore 20%(severe) to 60% (moderate) of all affected customers. This means that 132,000 to 396,000 customers would have lights back within seconds or minutes, representing a value of $3.3 to $9.9 million for a single storm.

The performance of some reliability programs can be tracked, and improvements in SAIFI indicates that a deployment is successful.  “Prior to the start of our program, our 2008 annual average Ohio SAIFI number was 1.33.  Our 2012 annual average Ohio SAIFI number is expected to be 1.03,” says Schneider.  He points out that the Grid Modernization program consists of other substation device automation and critical line device automation that also contributes to improved SAIFI.

 

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