Navigant Research Blog

Eastern Approaches to Smart Grid Development

— November 20, 2014

Japan and South Korea have emerged as leaders in smart grid technology development and deployments.  On a recent trip to East Asia I noted some similarities and some marked differences between the two countries’ approaches and styles.

At Korean Smart Grid Week in Seoul, I spoke about global demand response (DR) trends.  The Expo hall for the conference was as big as any I’ve seen, including large players like Korean Electric Company (KEPCO), Samsung, and LG exhibiting enormous booths and showing off cutting-edge technologies.  There were also a plethora of smaller companies and startups displaying their innovations to challenge the status quo and create the next-generation electric grid.

Next, I traveled to Jeju Island, the so-called “Hawaii of Korea.”  I got to enjoy the palm trees and volcanic landscape only by bus as we traveled to the Smart Grid Information Center, where KEPCO laid out its vision of the grid of the (not too distant) future.

Then we caught a quick ferry ride to tiny Gapa Island, which is only about 1 square mile in size but has an immense amount of solar, wind, and energy storage packed into a microgrid test bed, complete with a state-of-the-art operation center.

All of the Above

Next I embarked for Tokyo.  Japan is undertaking an “all of the above” energy strategy after the Fukushima nuclear accident in 2011.  Restarting the country’s nuclear plants is still on the table, but Japanese companies and government agencies are also deregulating the retail electricity market and designing opportunities for renewables, energy efficiency, DR, and energy storage.

Both countries, and the companies within them, have a laser focus on energy storage as a key solution, which is not surprising given their level of technological advancement.  Grid-scale energy storage is still a few years away in the United States, but Japanese and South Korean vendors are intent on leapfrogging Western suppliers and exporting their expertise.

Hare and Tortoise

The two countries’ business cultures, however, are quite divergent.  South Korean companies tend to take an aggressive, American-style approach to forming a plan, executing on it, and tweaking it along the way.  For instance, the country opened its DR market in November after a relatively short design phase, and U.S. provider EnerNOC has already entered the fray.

Japan, on the other hand, has been studying DR for a few years and it will take a couple more years of pilot programs until the market is ready.  Japanese firms tend to take a much more measured approach to development, trying to perfect the model before setting it free.  In the long term, both methods may work; but in the short term, the real action is in South Korea.

These developments are outlined in the new Navigant Research report, Demand Response for Commercial & Industrial Markets.  The report was actually published while I was abroad, so it includes updates from the trip.

 

Contrary to Trends, Constellation Spins Off Its Demand Response Unit

— October 7, 2014

The recent action in the demand response (DR) industry has been in the direction of consolidation.  Constellation (a unit of Exelon) bought CPower; Johnson Controls bought Energy Connect; NRG bought Energy Curtailment Specialists; and in Europe, Schneider Electric bought Energy Pool.  Only EnerNOC and Comverge are left as major independent DR providers.  The acquiring companies in these cases are large corporations that own generation, electric supply business, and/or energy management systems, intent on diversifying their product offerings and capturing more of the financial and customer value chain that DR provides.  These companies are also expanding into tools like distributed generation, solar, and energy storage to act as a one-stop energy shop for commercial and industrial customers.

Comverge’s just announced merger with Constellation’s Commercial and Industrial DR business is an exception to that trend.  The new entity will be an independent company, owned by Comverge’s parent company HIG Capital, with Constellation holding a minority stake.  In effect, Constellation is spinning off its DR business.  Is this just an anomaly, or is it a signal of a strategy shift across the industry?

Priority: Generation

I think that the Comverge-Constellation deal is a standalone case, due to circumstances specific to these companies.  Exelon values its large generation portfolio.  Services like energy efficiency and distributed generation, which mainly play on the retail side of the market, are not direct threats to the company’s wholesale generation revenues.  They can be incorporated into the retail supply business as value adders without negatively affecting the corporation’s main assets – its large generation facilities.

But DR for the commercial and industrial market is primarily a wholesale market product in the territories where Exelon has generation, such as PJM, ERCOT, ISO-New England, and NYISO.  In these environments, DR competes directly against generation: every megawatt that DR gets takes away from generation, and every cent the price of energy goes down thanks to DR comes out of generation’s coffers as well.  For Exelon, being a major operator of power plants while also running one of the largest national DR portfolios may have become too much of a conflict.  So, perhaps the company decided to break off the DR business and unify its wholesale market strategy.

Progress and Profits

Exelon’s distribution utilities run some of the most progressive DR programs in the country.  Baltimore Gas and Electric has the first default peak time rebate program in the country.  Commonwealth Edison recently announced a similar initiative.  PECO is piloting a dynamic pricing program.  Ironically, if Federal Energy Regulatory Commission (FERC) Order 745 on DR compensation gets overturned by the court system and DR becomes a purely retail product, Exelon may rethink its strategy and get back in the commercial and industrial DR game.  Then it might just be another customer product offering with less direct impact on wholesale markets.  From Comverge’s perspective, it saw an opportunity to substantially add to its commercial and industrial DR book.  The wholesale DR markets are all about scale these days, with players that can afford the credit requirements and aggregate large portfolios together to manage risk.  There are not big incremental costs to operate a bigger DR business – so the move should improve the company’s profitability.

 

Utility Customers Respond to Variable Pricing

— September 7, 2014

On July 23, Baltimore Gas and Electric (BGE) customers earned more than $2.5 million by reducing their electricity usage during peak summer heat hours.  Over 640,000 residences voluntarily participated – nearly an 80% participation rate among those who were notified – amounting to an average bill credit of $6.80, enough to buy an ice cream cone while turning down the air conditioning a few degrees.

BGE is the first utility in the country to put all of its customers with smart meters on a default Peak Time Rebate program.

It works like this: BGE customers with a smart meter can participate in the BGE Smart Energy Rewards program by voluntarily reducing their electricity usage to earn a bill credit of $1.25/kWh saved from 1 p.m. to 7 p.m. on designated energy savings days.  Eligible customers will be notified, usually the evening before, by an automated phone call, e-mail, or text message.  BGE anticipates that there will be 5 to 10 energy savings days in a summer season.

Smarter Grids, Smarter Customers

BGE has had a traditional direct load control (DLC) residential DR program for many years, and it has been successful within its own parameters.  However, the company has been installing advanced metering infrastructure (AMI), as covered in Navigant Research’s Smart Meters report, over the last few years, and with that network comes new capabilities (and regulatory requirements to meet cost-benefit thresholds).  AMI provides the utility and potentially customers with near-real-time interval meter data, so the utility can send time-based price signals and get almost immediate feedback on customer performance.  Couple these abilities with new end-user device and thermostat technologies that enable fast response and remote control by the customer, and you have more customer-centric, flexible demand response (DR) programs than were possible before; this can increase customer penetration rates dramatically.

Right on Time

Other innovative companies are trying different variations of programs and pricing offerings.  The Sacramento Municipal Utility District (SMUD) is looking to become the first utility to have a default time-of-use (TOU) rate after running a successful pilot that showed that customers preferred TOU structures to their standard flat rate.  The guiding principles of Oklahoma Gas and Electric (OG&E) for DR include voluntary participation for customers and no DLC by the utility, relying completely on customer empowerment.  OG&E believes that pairing dynamic pricing with technological devices will achieve these goals.  The province of Ontario, Canada has instituted default TOU pricing for customers with smart meters since 2005, the only area in North America to do so.  A traditional DLC program already existed in the province, and now the plan is to combine the control ability of the DLC with TOU pricing to help customers respond to price variations.  Massachusetts is set to become the first U.S. state to mandate default critical peak pricing (CPP) based on a recent order by the Department of Public Utilities.

All of these developments and other innovative programs are covered in Navigant Research’s new report, Residential Demand Response.  The report discusses industry trends around the world and provides 10-year forecasts of sites, capacity, and revenue, including breakouts between DLC and dynamic pricing.  Over time, all these different pilot projects will blossom into full-blown programs and expand into other jurisdictions, creating a truly responsive demand side of the energy equation.

 

New York Details Its Energy Vision

— August 27, 2014

The New York State Public Service Commission (PSC) has released its latest straw proposal on its Reforming the Energy Vision (REV) proceeding.  It includes recommendations that incumbent utilities take on the central Distributed System Platform (DSP) role, at least in the short term.  This was one of the most controversial issues in the REV plan, with the potential for the utilities to be stripped of many of their responsibilities by the PSC and replaced by a new independent entity.  PSC staff decided to stick with the utilities – partly for substantive reasons, partly out of expediency.

The paper includes a table comparing the roles of a utility versus a DSP, exhibiting a great deal of overlap.  So the utilities can breathe a major sigh of relief with that recommendation, knowing that they will maintain many pivotal duties.  But the paper does point out that utilities do not currently have all of the capabilities and competencies needed to successfully operate the DSP and will need to hire new staff with different skill sets, as outlined in my earlier blog on utility hiring trends.

Seeking Alignment

Also noteworthy, from the standpoint of demand response (DR) and distributed energy resources (DER), is the recommendation that all utilities be required to develop DR tariffs, including fees for storage and energy efficiency.  PSC staffers are wary about the potential effects of the pending U.S. Circuit Court case on Federal Energy Regulatory Commission Order 745 on DR compensation, which could complicate DR participation in wholesale markets like the New York Independent System Operator (NYISO).  On the other hand, the report is rather light on recommendations for expanding time-of-use rate structures, which may also encourage increased DR participation.

Addressing the concern about a lack of coordination between retail and wholesale markets, the report states that market rules allowing DER participation in both markets must be aligned to ensure that DER interaction is efficient and properly valued.  The PSC argues that this goal can be accomplished with DSPs acting as aggregators in NYISO programs.  That’s a threatening statement to the third-party DR aggregators that would not want the utility/ DSP to compete with them in the wholesale markets.

Are Smart Meters Necessary?

From the consumer perspective, the report references a recent survey of residential electricity customers in New York that found that, although few customers say they are knowledgeable about their electricity usage, many place a high value on easy access to information regarding their energy use, the price of electricity, and methods for controlling their energy costs.  This indicates the potential for substantial increases in residential customer adoption of home energy management and DER products.

Notably absent from the REV plan is a recommendation regarding advanced metering infrastructure (AMI).  Electricity cost and rate increases are sticky political issues in New York currently, and PSC staff did not highlight AMI as a requirement for achieving REV goals.  The only reference to AMI actually speaks to how to avoid it: “To the extent that the cost of advanced metering equipment presents a barrier to customer adoption of DER programs or time variant pricing, utilities and market participants should consider alternatives to AMI technologies to enable program delivery.”  In other words, the report acknowledges that AMI functionality may be useful for REV purposes, but doesn’t say how that functionality can or should be achieved.

Comments on the straw proposal are sure to be plentiful from all sides.  I view this plan as less aggressive than the original REV paper, but ultimately, it is more achievable in the short term – which may help build momentum for the longer-term transformation.

 

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