Navigant Research Blog

PLMA Fall Conference Highlights Key Trends in the DR Industry

— December 2, 2016

Power Line Test EquipmentIn early November, the Peak Load Management Alliance held its annual fall conference in Delray Beach, Florida. Aside from the election excitement surrounding the conference, some interesting sessions and trends emerged from the meeting.

The conference agenda has expanded over time as more special interest groups have formed to tackle hot topics in the industry. Community storage and thermostat groups have been meeting for the past several conferences, and this year customer engagement and retail pricing groups were added to the mix. The retail pricing group had a lot of ground to cover and had to first define the boundaries of its scope, since pricing can become a very broad topic if not properly fenced. There was an interesting dichotomy between the public power agencies, which have freedom to offer whatever rates they please, and the investor-owned utilities, which must get regulatory approval for any new rate structures.

Rate Making at the Center

The full conference got underway with an opening panel on rate making. Edison Electric Institute moderated a group including NRG Curtailment Solutions, Georgia Power, Consolidated Edison, and the Independent System Operator of New England. The panel showcased a wide range of perspectives based on varying beliefs in the power of competitive markets, the coordination between retail and wholesale markets, and whether utilities should get directly involved in customer enablement or if it should be left to market players.

Next, some utilities explained their demand response (DR)/smart grid programs for residential customers. National Grid detailed its Smart Energy Solutions pilot in Worcester, Massachusetts, which provided smart thermostats and Wi-Fi gateways to customers. Old Dominion Electric Cooperative described how it went beyond hardware to obtain more DR from customers through innovative communication methods to encourage behavioral changes based on pricing and usage information.

I had the pleasure of moderating a panel on demand response management systems (DRMS) that included PECO, NV Energy, and Consumers Energy. Each of the utilities outlined their implementation experiences with different DRMS vendors and offered best practices and lessons learned to those in the audience who hadn’t yet gone through the process.

Varieties of DR

After lunch, a panel that included North Carolina Electric Membership Corporation, NB Power, ecobee, Portland General Electric, and Nest covered the topic of winter DR. Winter DR has garnered interest in northern climates as well as areas where natural gas constraints are causing a lack of electricity generation (i.e., New England, PJM, and California).

After a long election night, presenters provided a smorgasbord of ideas throughout the next day. Hawaiian Electric discussed the impact of energy storage in combination with automated DR. Duke Energy outlined lessons learned from a smart thermostat program that did not get the desired benefits. CPower navigated the muddy waters of DR in California. National Grid and Weatherbug Home explained how to leverage Internet of Things devices for customer engagement.

The conference closed with a thought-provoking session with speakers from NV Energy, Skipping Stone, Navigant, Alternative Energy Systems Consulting, and Joule Assets pontificating upon the future of the DR industry. I’m looking forward to seeing everyone again in Nashville in April for the next round.

 

EnerNOC Restructures: Is It Back to Basics for the Demand Response Company?

— October 13, 2016

AnalyticsA couple of weeks ago, EnerNOC announced a restructuring, a move which included laying off 200 employees, about 15% of the demand response leader’s workforce. Many of these positions were at its corporate headquarters in Boston. I didn’t want write on the topic until I had a chance to talk directly with the company and get its side of the story, which took a week or so of phone tag to complete. Here’s what I heard and my reaction.

I spoke with Sarah McAuley, senior director of marketing at EnerNOC. She explained that the layoffs were focused on the enterprise software side of the business, and they were cross-functional across sales, operations, and other functions. I have since learned that employees in other parts of the organization that dealt with the software business tangentially were also affected by the restructuring. There were no changes to the senior management team, but changes did extend up to the vice president level. McAuley said that there is nothing else at this scale planned in the near future, but that EnerNOC is taking a close look at how it is operating the business and will continue to optimize resources and shift personnel around the edges.

McAuley also stated that EnerNOC is not retreating from the software business, and the company’s core strategy hasn’t changed. However, its go-to-market path and operational delivery models will be different, focusing on becoming more targeted and lean rather than wide and broad.

Pivot to Software

I remember first hearing about the company’s pivot to software at EnerNOC’s Analyst Day in 2013. At the time, it seemed to me like a risky proposition; EnerNOC is not a software company at heart, and it was an uphill battle against the incumbents to carve out its space in that field.

A similar experience appears to have occurred in the energy efficiency space. EnerNOC made a series of acquisitions over a span of 5 years or so, trying to parlay its demand response position into that adjacent space. All of those deals have since been unwound, presumably at a loss.

It’s important to remember that public companies need to take risks to show constant growth for shareholders. Not all of these are expected to completely succeed, but it appears that few have worked outside of EnerNOC’s core competencies.

Potential Paths Forward

So what’s next? Being the only publicly traded demand response/energy efficiency company left, there are a couple examples of previous outcomes. Comverge, EnerNOC’s closest peer, also went public in the heyday of the economy during the last decade. It only lasted a few years before being bought out and brought private, and it has continued to operate steadily since that time. Opower is the most recent case, having tried the public life for a few years before being acquired by Oracle earlier this year—time will tell how that situation will play out. One of those two scenarios seems plausible for EnerNOC at this point, either going private or being swallowed by a larger corporation (though I am not a financial professional, so don’t take this as investing advice).

In any case, I hope EnerNOC’s passion for and leadership in the demand response field will not be lost. Its tide has truly lifted all boats in the sector, and there is a lot of work left to be done to ensure that it keeps its place in the world’s future low-carbon resource mix.

 

US Drought Puts Spotlight on Demand Response Management Systems

— September 9, 2016

TabletThe extreme heat and drought that has engulfed much of the United States this summer has led to the most active demand response (DR) season in many years. Regional transmission organizations (RTOs) and utilities across the Mid-Atlantic and Northeast regions such as PJM, Independent System Operator of New England (ISO-NE), and Consolidated Edison (Con Ed) all called upon DR to alleviate peak demands in excess of available generation resources or extraordinarily high real-time energy prices.

In the old days of DR, this process would have entailed a lot of phone calls and manual interactions that have a lot of failure points and a lack solid feedback mechanisms. As the scale of DR programs has increased, their operational reliability has become more critical and the choices of communication protocols and devices have expanded. There is a need for more centralized management and control, similar to what is done on the power generation side of the electricity market. Numerous vendors have come from many different angles to offer solutions that are categorized as demand response management systems (DRMSs).

Developing Vendor Offerings

DRMSs are developed to help utilities manage their DR programs and improve program ROI, though to date vendors indicate that the uptake of DRMSs has been slow. The core functions of DRMSs are to allow utility operators to view and add to the database of loads available for DR, to call events and/or issue pricing signals, and to perform the measurement and verification (M&V) after events to determine how much customers need to be compensated for reducing their load. In addition to this core functionality, there are many other functions and analytical tools that can be built upon this platform.

Outside of the strictly regulated utility construct, competitive retail energy suppliers have also offered DR programs to their electric commodity customers in order to provide more value and increase customer loyalty. The most striking examples are in Texas, where all customers must choose a competitive supplier as utilities are not allowed to provide supply services. Some retailers in the United States are active only in certain regional markets, while others have coverage in most—if not all—of the competitive markets. As with utilities, retailers could develop their own DRMS capabilities in-house, but in most cases it is not worth the effort. In recent years, Direct Energy has selected Siemens for its DRMS; NextEra Energy chose AutoGrid.

DRMS Drivers

The key drivers for advancing DRMSs include technical, policy, and economic factors such as DR program management, internal and grid cost reductions, and integration with other utility information technology (IT) and operational technology (OT) systems. However, the slow rate of DRMS development points to the depths of barriers, such as system cost, integration complexity, and flexibility and interoperability limitations as being major hurdles to be overcome.

These trends and more are covered in Navigant Research’s new report, Demand Response Management Systems. Utilities are just starting to gain interest in DRMSs now, but as resources like solar and energy storage grow, DRMSs will act as a bridge to distributed energy resource management systems (DERMS).

 

Distributed Energy Resources Hit the Auction Blocks in California and New York

— August 30, 2016

Cyber Security MonitoringAs we head into the fall fantasy football season, this summer has been good practice for those in the distributed energy resource (DER) world to value their portfolios and bid into auctions to provide their services. In both California and New York, utilities recently held auctions to procure DER to address electric grid needs. Although the outcomes are similar, the methodologies to get there were quite different.

First, California’s investor-owned utilities—Pacific Gas and Electric (PG&E), Southern California Edison (SCE), and San Diego Gas and Electric (SDGE)—ran the second edition of the state’s Demand Response Auction Mechanism (DRAM). Since the California Independent System Operator (CAISO) does not have a capacity market, the California Public Utility Commission (CPUC) ordered the utilities to offer DRAM as a way to incentivize DER to provide similar product characteristics to capacity. In total, the utilities procured almost 82 MW, about 4 times the minimum requirement of 22 MW. However, a group of bidders is currently petitioning the CPUC, arguing that the utilities could have procured even more resources within their budgets.

New York took the spotlight in the form of Consolidated Edison’s (ConEd’s) Brooklyn Queens Demand Management (BQDM) auctions in July. Unlike DRAM, which is concentrated on statewide capacity issues, BQDM is a focused effort to relieve distribution constraints in a targeted area of high load growth. While final results are not yet public, initial information from ConEd states that 22 MW of resources were procured for 2018 from 10 bidders, with clearing prices ranging from $215/kW/year to $988/kW/year. These prices are much higher than ConEd’s existing demand response programs, which pay in the area of $90/kW/year, and the New York Independent System Operator’s (NYISO) capacity market, which offers around $130/kW/year in ConEd’s territory.

Different Mechanisms

There are some notable differences between the DRAM and BQDM mechanisms. First, DRAM has one product with a standard set of requirements that all bidders must meet and compete against. BQDM has two separate product types that bidders must choose to offer, one for the 4-8 p.m. time period and another for the 8 p.m.-12 a.m. period. These 4-hour blocks were created to allow energy storage devices with 4-hour charging capacities to participate.

Another major difference is the auction process itself. DRAM is a pay-as-you-bid format, where bidders submit their offers by a deadline and then the utilities review them and select the least-cost combination of bids, with each bidder receiving its submitted price. BQDM, on the other hand, is a live, descending clock auction, in which bidders log into an auction platform at a given time and can submit bids as prices are displayed. The price keeps decreasing until the auction reaches its desired number of megawatts. Then all remaining bidders receive that uniform clearing price, even if they would have bid lower than that price. The pay-as-you-bid versus uniform clearing price debate is a classic economic debate that has raged for years.

As usual, there are multiple paths that can achieve similar goals. Best practices and lessons learned will be observed with experience—but I doubt if California and New York will ever admit that the other did something better.

 

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