Navigant Research Blog

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.


National Town Meeting on Demand Response Confronts Key Industry Issues

— August 3, 2016

Power PlantIn the heat of the summer demand response (DR) season, industry thought leaders met in Washington, D.C. for the 13th annual National Town Meeting on Demand Response and Smart Grid. This was the first year that the Smart Electric Power Alliance (SEPA) took over responsibility for the event since subsuming the Association of Demand Response and Smart Grid. The transition appeared to be smooth, as the program included all of the successful ingredients from the past town meetings.

The event kicked off with a greeting from Julia Hamm, the president of SEPA, who expressed her excitement at being involved. She moderated a panel of industry experts on SEPA’s 51st State Initiative, which is intended to envision an ideal state regulatory and market structure for clean energy starting from a clean slate. That session was followed by an intimate discussion with Phil Moeller, former commissioner at the Federal Energy Regulatory Commission (FERC) and current senior vice president at the Edison Electric Institute. Phil opined on many industry issues, including the FERC Order 745 saga, about which he said that FERC jurisdiction was just a distraction from the more relevant concern about DR compensation levels.

Changing Utility Landscape

Next, a group of state public utility commissioners (PUCs) from across the country provided thoughts on the changing landscape in the energy industry and what it means for regulators. Willie Phillips, Commissioner on the Washington, D.C. PUC, noted three P’s that should be the focus: policy, prices, and people. He also commented that industry restructuring promotes competition and competition promotes innovation. Utility executives had an opportunity to respond on their own panel and talk about new business models and revenue drivers. Paul Lau, Chief Grid Strategy Officer for the Sacramento Municipal Utility District (SMUD), highlighted that SMUD’s peak load occurred 10 years ago and has been flat or declining since then, a trend that is affecting many utilities.

The second day of the conference was broken into three distinct tracks reflecting the diversity and broad scope that DR and smart grid are touching upon. The Grid Integration track covered technology trends such as distributed energy resource management systems, solar and storage partnerships, microgrids, automated DR, and electric vehicle integration. The Emerging Models and Markets track included panels on time varying rates, cost-benefit analysis for grid modernization, policy and regulatory evolution, the future of regional transmission organization markets, and distribution planning tools. Finally, the Consumer Engagement track looked at modernizing communications and outreach, advanced customer engagement, consumer-driven technology adoption, data analytics for customer engagement, and innovative commercial and industrial DR programs.

The breadth of this year’s National Town Meeting represents the growing importance and integration of all types of resources on the electric grid. By the time of the 2017 meeting, we might have entirely new terminology to describe these trends on a system level, rather than talking about individual technologies and policies.


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