Navigant Research Blog

May Comes in like a Lion for Demand-Side Management

— May 11, 2016

multimeterLast week was a busy one in the demand-side management (DSM) industry, with M&A activity and regulatory news both making headlines. It started first thing on the morning of May 2 with the announcement that Opower was being bought by Oracle for over $500 million. This move shouldn’t be so surprising since it was just over a year ago that the two companies announced a partnership to enable utilities to integrate Opower’s tools into Oracle’s systems and vice versa.

EnerNOC is now the only publicly traded pure-play DSM provider left standing. Could it be that dealing with the regulatory risk and long timeframes for deal making in the utility industry is a mismatch with Wall Street’s pressure for quarterly earnings? Opower appeared to have a good pipeline of projects, but the market did not seem to value it enough to provide attractive returns for investors. Furthermore, the energy software business requires extensive R&D spending, so the prospects for an annual profit were too long for the NASDAQ set. As part of a larger organization, the long project runways could be blended in with other quicker turnaround products, and R&D expenditures could be swallowed among the much larger expenses at Oracle. The only question is how committed Oracle is to Opower’s legacy DSM products versus focusing on solutions more directly in line with its business.

CPower on the Move

Later that same day, word spread that CPower acquired rival Johnson Control’s Integrated Demand Resources business. This move thins the already-small commercial and industrial demand response (DR) aggregation sector. It also continues the trend of larger organizations getting out of the DR business, which started when Constellation sold off CPower in 2014. For CPower, the acquisition is the latest move to expand following the purchase of Demand Response Partners in 2015. CPower and Johnson Controls still intend to retain a commercial relationship that would allow CPower to offer DR services to Johnson’s customers, and CPower customers could gain access to Johnson’s building management technologies for their facilities.

These cases appear to show some contradictory trends between acquisitions and divestitures of DSM businesses by larger entities. However, they both seem to agree on the point that DSM may survive either as part of a bigger firm or as an independent private company, but as a standalone public entity, the road ahead is hard. Look at Comverge, which went public in 2007 but went back private a few years later and has seemed to steadily grow under the radar since then, or Nest, which is able to keep its finances out of public view as part of the Google empire.

Emergency Generators

The final piece of noteworthy news relates to the U.S. Environmental Protection Agency’s (EPA’s) rules for emergency generators (EG) for DR purposes. Last year, the U.S. Court of Appeals overturned an EPA rule that allowed 100 hours of EG use for emergency DR programs. It granted the EPA a 1-year stay, which expired on May 1, 2016. The EPA has no plans to make changes to the rule, meaning that the court’s ruling will remain intact, affecting upward of 20% of DR resources in some markets.  However, there is still some ambiguity in the remaining EPA rule language, so the fight will continue to allow EG to participate to some extent.

If the first week of May was any indication, it could be an interesting summer for DSM, but these recent developments may have been just some early fireworks before a regular course of business settles in.

 

Recapping the PLMA Spring Conference

— May 2, 2016

Home Thermostat DialThe Peak Load Management Alliance’s Spring Conference was recently held in San Francisco from April 18 to 20. It felt great to be back in the Bay Area after having worked out there on the first generation of demand response (DR) programs to help avert rolling blackouts following the Enron mess. That saga is well in the past now, but DR continues to evolve and adapt to the changing market conditions due to technology, policy, and economic forces. Leading practitioners and visionaries in the industry were at the conference, trading opinions on several themes that coalesced as the event progressed.

The concept of integrated demand-side management was discussed from a couple of different angles. First off, there’s the combination of energy efficiency and DR program offerings based on enabling technologies like smart thermostats and targeting specific geographic territories. Utilities like NV Energy and Commonwealth Edison reviewed their thermostat experiences, while Consolidated Edison, Central Hudson, Pacific Gas & Electric, and National Grid explained how to drill down to the distribution level to address location-specific constraints. Successful implementation will require breaking through the traditional utility and regulatory silos that separate energy efficiency and DR operations and budgets.

Second, there was the concept of integrating DR with other distributed energy resources like energy storage and solar PV as a full-service offering for customers that addresses their concerns outside of technology silos. Hawaii and California were highlighted as areas that are dealing with this market shift in real time, leading to new operational system needs and program design structures.

Some of the early utility and vendor adopters of the BYOT, or Bring Your Own Thermostat, design concept—including Xcel Energy, SCE, Great River Energy, Nest, and EnergyHub—provided their best practices and lessons learned, while the audience pondered how quickly this model could go mainstream. There was a lot of discussion about the technical and operational barriers to bringing BYOT to scale and maximizing customer engagement without turning them off through excessive hoops to jump through. It was mentioned that the seemingly simple step of requiring a customer to provide a utility account number in order to sign up for a program dramatically reduces the likelihood of enrollment.

The next opportunity for DR thought leaders to convene will be the National Town Meeting on DR in Washington, D.C., running from July 11 to 13. It might not be as exciting as it was to be in D.C. last fall for the Supreme Court hearing on DR, but there should be plenty to talk about as the presidential election heats up.

 

It’s a Small World (for Dynamic Pricing) After All

— April 4, 2016

multimeterDisney recently unveiled surge pricing for its theme parks, meaning that tickets will cost more during holidays and on some weekends—up to 20% more—than during slower periods as the near-capacity parks seek to spread out demand. When Mickey Mouse announces this strategy, it’s hailed as a brilliant business move. So why is it that when utilities try to roll out dynamic pricing options, it is assumed it will lead the elderly and orphans to swelter in the heat and sit in the dark?

Dynamic pricing exists in many aspects of society, such as with airline tickets, theater and sporting event tickets, subway fares, and road tolls. The basic concept is that the value of a product varies based on time, demand, and other factors, so being able to charge prices that better reflect that value is more economically efficient than simply charging an average flat price across all hours and variables. Makes sense, right?

In the electricity industry, the concept of dynamic pricing for mass-market customers is fairly recent (aside from time-of-use rates). With the proliferation of advanced meters that can record usage at small intervals, more types of dynamic pricing can be applied down to the residential level.

The key drivers for advancing dynamic pricing include technical, policy, and economic factors such as:

  • Advanced metering infrastructure (AMI): Without the 15-minute interval data provided by smart meters, or AMI, dynamic pricing programs cannot accurately be implemented. Smart meters are now seeing more widespread deployment, which further enables the market for dynamic pricing.
  • Utility and customer costs: Offering a dynamic pricing program to reduce peak demand may be cheaper for a utility than building a peaker plant to meet increased demand. On the customer side, electric bills can be reduced by modifying consumption behavior. In the long run, all ratepayers should see lower rates than they otherwise would due to the increased capacity factor and avoided infrastructure costs.
  • Enabling technologies: Devices such as smart thermostats, smart appliances, and associated home energy management applications are becoming more commonplace, allowing consumers to more easily manage their energy demand.
  • Distributed energy resources (DER): As DER capacity from resources like energy storage and electric vehicles grows, so does the ability to shift load and enjoy the cost savings from dynamic pricing programs.

However, the slow rate of dynamic pricing program development points to the depths of the barriers to such growth:

  • Reliable service concerns: Utilities understand how important reliability is—especially for at-risk residential customers, including low-income customers, the elderly, families with young children, and the disabled—and seek to provide a resilient grid that operates disruption-free. Without proper education about the program, dynamic pricing rates could potentially send a harmful signal to these at-risk groups.
  • AMI integration: Systems integration plays a huge role in the success of AMI techniques and poses a significant cost to utilities. Ensuring AMI provides flexible and extensible solutions is paramount.
  • Lack of customer education and demand: Customer understanding of dynamic pricing is low. Unlike other energy management strategies that focus on different aspects of energy consumption, dynamic pricing depends on modulating customer habits, which may be hard to change.

There are several examples of utilities implementing successful dynamic pricing programs, such as Baltimore Gas and Electric, Oklahoma Gas and Electric, and Sacramento Municipal Utility District. These topics and more are covered in Navigant Research’s new report, Dynamic Pricing. Perhaps learning about dynamic pricing from Disney will lead more people to embrace it in other parts of their lives.

 

Integrated Demand Side Management Gathers Steam Through Targeted Approaches

— March 17, 2016

Network switch and UTP ethernet cablesIntegrated demand-side management (IDSM) has been a topic among DSM professionals and utilities in the United States for a decade. However, efforts to integrate energy efficiency and demand response (DR) in utility programs thus far has been challenging, and little progress has been made. Traditionally, energy efficiency and DR have been siloed within utilities, with misaligned goals and barriers to transferring funds between programs. Yet, the integration of DSM programs has become increasingly popular, especially in places such as California, where the combination of these programs has been used as a fundamental part of the state’s energy planning and strategy.

There is no standard definition of IDSM at this point in time, but the most common definition combines energy efficiency and DR technologies. There is also an aspect of integrating electric and gas DSM programs. More recently, integration has evolved to include other resources such as energy storage, solar, and fossil fuel-based distributed generation. The key drivers for advancing IDSM include technical, policy, and economic factors, such as increasing DSM goals and regulatory pressures, program cost reduction potential, targeted DSM, grid modernization, and smart thermostats.

Barriers to Overcome

However, the slow rate of IDSM program development points to a number of barriers to be overcome. These include utility organizational structures and budgets that are siloed and hard to cross-promote; energy audits that don’t consider both types of measures; cost-effectiveness and measurement and verification challenges with accounting for both types of benefits and potential double-counting; vendor conflicts of interest; and niche, early-adopter customer markets that may not accurately reflect the mass market potential for these offerings.

The move toward targeting DSM to specific distribution-level areas with high load growth or infrastructure constraints appears to be a growing trend. Historically, DSM programs were administered state- or utility-territorywide as a means to reduce overall system energy usage. As the electric grid has aged and general load growth has slowed due to economic conditions and the success of large-scale DSM programs, a more discreet form of DSM may be more effective and efficient. Even if systemwide load growth slows, many utilities will still have areas on their network with higher growth rates due to residential or commercial development.

An all-of-the-above DSM approach is valuable in such cases, since it may be unrealistic to have separate energy efficiency and DR vendors and marketing efforts to a small geographic territory. A combined effort makes sense so as to not overload customers with multiple messages. The concept of a non-wires alternative (NWA) has entered the lexicon, where a utility will look at other means of meeting its reliability requirements at a lower cost than a traditional distribution capital expenditure upgrade. Utilities such as Con Edison, National Grid, and Central Hudson have recently initiated such targeted DSM programs to address acute system needs.

Navigant Research’s new report, Integrated Demand Side Management, covers these topics and case studies in addition to forecasting of future growth of IDSM. As utility models, policies, and technologies evolve, the integration of various resources will only increase in practice and importance.

 

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