Navigant Research Blog

Military Tackles EVs, Smart Grids

— October 7, 2011

Innovative technologies find fertile ground where conundrums meet persistent minds.  It also doesn’t hurt to have extensive resources available.  The military has often provided both halves of that equation, bringing determined thinking and ample resources to bear on technology development.  As it did in the case of the Internet, the military is now bringing both to bear on the challenges of the smart grid, distributed generation, and sustainable transportation.

The current delivery system for electricity is tied to an antiquated transmission infrastructure that’s being bombarded with renewable-energy installations at the same time that peak demand is soaring.  In the Western United States, the energy strategy moving forward is based on long-distance, high-voltage transmission of resources from rural America.  Meanwhile, funding for research and development related to the grid has dropped significantly as outages and costs continue to multiply.  This situation has left the cities of the West increasingly susceptible to blackouts like that experienced in early September, when six million people across Arizona and Southern California were hit with the worst blackout experienced in 15 years.  Grid outages such as these cost billions of dollars in damage, restoration costs, and economic slowdowns.

This sort of man-made failure is unacceptable to the Pentagon.  Thus, enter the United States Air Force, which recently declared its intention to test a service business model with electric vehicles and vehicle-to-grid technology at the Los Angeles AF Base.

The Los Angeles AF Base will convert its entire non-combat, general purpose vehicle fleet to plug-in electric, either fully electric or hybrid; about 40 vehicles are eligible.  What will begin as a pilot program, in support of the Department of the Air Force’s green goals, could eventually result in a massive deployment of electric vehicles at Air Force bases around the world.  The goal is to demonstrate whether the Air Force can generate revenues by providing frequency regulation through advanced vehicle-to-grid (V2G) technology, revenues that would offset the costs of procuring an EV fleet.  Peak shaving, renewables integration, and load shifting could be incorporated in the Air Force’s business model in future.

This V2G technology is a new approach to managing electric vehicles and to monetizing grid services.  There are only a handful of demonstration projects in place across the globe, with only a few firms actively involved.  These projects are encouraged by deregulated markets that are taking a fresh look at market structures and revamping regulatory regimes relating to grid services.  This may be just the tip of the iceberg for a new market opportunity in grid services.

The application of the U.S. military’s resources to the issue of grid reliability creates opportunity to apply original thinking to problems faced in the civilian world.  The Air Force’s EV and V2G programs will provide an early indicator whether technologies could eventually take root and flourish in a broader context.

 

Energy Storage Maximizes Transmission Infrastructure

— October 6, 2011

Transmission and distribution (T&D) deferral is a key application for energy storage. A common example is deferring the upgrade of a substation by co-locating a battery at the site.  This has been demonstrated at several sites, including by AEP in Ohio, Texas, and West Virginia, and by TEPCO in Japan.  In these cases, NGK Insulator’s sodium sulfur (NAS) batteries were used to defer the upgrade of the substations.  The value of such “virtual upgrades” for energy storage is direct and obvious enough to justify to public utility commissions or other stakeholders.

Other examples for energy storage include wind and solar integration.  As new regulations encourage wind and solar project developers to firm up capacity of intermittent resources or developers seek to maximize their installed capacity, new opportunities for energy storage technologies will arise.

Suitable applications include wind ramping, solar firming, peak smoothing and others. The value of these applications for storage are less straightforward to pin down.  Certainly smoothing instability from intermittent resources is a good thing for the grid; but is there an incentive (regulatory or monetary) to do so?  In many cases there’s not, or it’s not obvious.  Likewise, are intermittent resource developers obligated to maximize the capacity factor of installations in order to turn a profit?  Again, the answer is rarely.

One application highlighted by speaker Jim Robb of Northeast Utilities at the Energy Storage Summit in Houston last week brought the two together: T&D deferral to connect remote, intermittent resources to load centers.  From the perspective of T&D utilities, new transmission lines to remote resources such as wind farms are often hard to justify.  In Robb’s example, the cost of a transmission line to bring wind-generated power from mountainous New Hampshire to load centers in Connecticut and the Boston area added $.06 per kilowatt hour to the cost of electricity from the wind installation.

In addition, because the new transmission line would not increase reliability or improve congestion, it would be classed as an “economic” project, which is more difficult to get funding for in the first place.  Robb ran several scenarios, assuming nearby small pumped storage installations, and the results were fairly intuitive: by including storage a wind farm can be “oversized” relative to the available transmission line, the wind asset can take fuller advantage of the transmission line, and the overall transmission cost decreases.  This is largely thanks to the increased capacity factor for the wind farm when wind is coupled with storage.

This type of T&D deferral is important for several reasons: It maximizes intermittent resources, opens up T&D deferral applications to materials-based energy storage (as opposed to electrochemical storage), addresses the infrastructure issues of intermittent renewables, and gives storage a clear business case for renewables integration.

 

Allez Linky!: France Greenlights Smart Meter Program

— October 5, 2011

The French government has formally approved the deployment of 35 million electricity meters, starting in 2013 with completion by 2018.  Deploying the Linky meter to customers across France will cost an estimated €4.3 million ($6.2 million).  The government also confirmed that the cost of the rollout is expected to be borne by Électricité Réseau Distribution France and recouped through new network efficiencies.

The project follows the completion of a successful trial of 300,000 meters around Lyon and the Indre-et-Loire department, involving Atos Origin, Itron, Landis+Gyr, and Iskraemeco.  There had been concerns that the government might delay plans for deployment given the financial crisis in the Eurozone and a presidential election beckoning next year.  The announcement that the project will create around 10,000 new jobs will help sweeten the pill politically.

The major challenge in France will be to ensure consumer acceptance.  There is a perception amongst consumer groups that the meters are primarily for the benefit of the electricity industry (dominated in France by nationwide utility EDF and its subsidiaries) and that in the end consumers will be bear the price of the meters.  Only minimal support for consumer energy efficiency is required in the basic rollout and energy retailers can charge more for additional information services.  A lot more work will need to be done if the meter is to play a role in reducing household costs and improving energy efficiency. 

These challenges reinforce more general issues that are becoming evident in the European push to deploy smart meters.  The arguments in favor of smart meters are well rehearsed, but as European deployments accelerate, it’s clear that aligning the interests of all the potential stakeholders is no easy task.  In Europe, the European Commission has promoted smart meters as part of its overall energy policy – with the new technology seen as helping address energy efficiency and also market liberalization.  The basic concept is that if consumers are more aware of the price they are paying for electricity then they will both reduce energy consumption and also be able to find better rates from other suppliers in a deregulated market.  That’s the theory anyway.

But European policy has also promoted the disaggregation of energy suppliers, with distribution networks and energy retails provided by separate players or between regulated and non-regulated entities from single suppliers (as in France).

This separation highlights a disconnection between the goals of the distribution systems operators and the energy retailers.  Where this split is most developed – as in the United Kingdom – it raises issues as to how a holistic view of the requirement for smart grid investment can be achieved.  Smart meters in the United Kingdom are largely being cost-justified by the potential benefits to consumers and retailers.  Distribution system operators (DSOs) have been involved in the specification but it remains a secondary concern for them compared to the work that needs to be done on improving the network to support renewable integration, for example.

However in most of Europe, it is the distribution company that is responsible for smart meter deployment. As someone from a German DSO said last week, they can’t justify smart meters purely in terms of the benefits to network improvements, as they can achieve the same ends in a more cost-efficient manner (for example, by the strategic placement of many fewer network sensors).  That is not to say the smart meters have no benefits.  DSOs will happily use any data that can be provided, but they can’t make a standalone business case.  ERDF is reported as saying that it will take 20 years to achieve payback on the Linky deployments from improvements in network efficiency.

It is clear that if European countries are to meet the target of deploying smart meters to 80% of customers by 2020, then they need to focus equally and consistently on the two challenges of consumer engagement and providing incentives to network operators.  The need for a holistic view of the smart grid is a commonplace, but realising it within specific market structures is the real challenge.

Moving towards a European smart grid is a huge engineering challenge, but given the social, environmental and market issues also at stake it sometime looks more like an exercise in advanced plate spinning.

 

Utilities’ IQs Rising

— October 5, 2011

U.S. utilities are getting smarter, and smart grids are making the difference.  This theme permeated the recent Autovation 2011 conference in suburban Washington, D.C., which provided an overview of trends and recent developments.

How smart?  No one from the utilities admitted to failing grades, of course, but various company representatives using smart technology report measurable progress:

  • Pepco’s Bill Gausman, senior vice president of strategic initiatives, told the opening session that his utility’s smart grid outage-detection system came up big during Hurricane Irene.  The system had 150,000 meters reporting in, and managers equipped with this data were able to eliminate 600 truck-rolls in Maryland alone (which, using a back-of-the-envelope calculation, works out to some $90,000 in savings).
  • John Stafford, vice president of sales at Sensus, said he initially underestimated the benefits of smart grid technology for consumers.  He told the audience his own projected bias was that only a “lunatic fringe” would be interested in modifying their usage once empowered with consumption data.  However, consumers are interested in using Web-based reporting portals, he said; adoption is in the 20% range.  He cautioned the audience to guard against personal bias, and allow the actual data to speak for itself.
  • Portland General Electric’s project manager technology support, Eric Spack, said his utility’s installation of smart meters will bring an estimated return on investment (ROI) of $35 million (net present value) in operational cost savings.

Two other companies offered interesting updates on their efforts:

Craig Kuennen, business transformation and marketing administrator for Glendale (California) Water & Power, described how GWP has deployed smart meters across its system, and is in trials for the rollout of CEIVA photo frames early next year that will allow consumers to not only share pictures over a ZigBee-enabled home area network, but also engage them with a water and electric management dashboard. Pretty cool.

Echologics’ Marc Bracken, vice president and general manager, presented a fascinating case study of how his company’s non-invasive acoustics technology enabled the Sewerage and Water Board of New Orleans (SWBNO) to detect and conserve thousands of gallons of lost water per day.  The technology can accurately pinpoint leaks without the use of digging, and in one instance uncovered a significant leak underneath a sidewalk that was costing SWBNO an estimated $200,000 per year.

One of the more lively sessions at Autovation took place during a panel discussion among meter vendors. Aclara’s Paul Lekan, vice president of marketing (and one of the most entertaining personalities in the utility business, I might add) made a strong point about how great the new meters are, but that “it’s all about the data” – and how utilities manage the information they collect and leverage analytics to their advantage.  He cited one utility his company has worked with that saw a dramatic change in customer service calls: before the new technology was installed, 90% of calls were inbound, and now that has been reversed by utilizing data to proactively reach out to customers.

The takeaway from Autovation: Deployments of smart technology may be longer-term bets, but for utilities that have deployed them already some of the payoffs are evident now.

 

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