Navigant Research Blog

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.

 

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.

 

What DER Business Models Will Gain the Most Traction in 2016?

— February 4, 2016

Power Cloud ComputingAccelerated adoption of distributed energy resources (DER)—whether talking about solar PV,  batteries, or demand response—appears to be a foregone conclusion. While the growth rates for different applications will vary in different parts of the world, there is little doubt that the future power system will be populated with increasing amounts of smaller, cleaner, and smarter sources of electricity services.

It is also fair to say that the primary challenge facing both utilities and regulators is to figure out which business model makes the most sense for each technology, application, and market. This is not a one-size-fits-all question.

While the DER spectrum is broad, let me focus on a networking platform that can aggregate and optimize: the microgrid. Platforms such as the nanogrid avoid many of the regulatory complexities facing its larger compatriot microgrid. The growing popularity of linking solar PV to energy storage for both commercial and residential single building sites is relatively straightforward. However, once a network expands across public right-of-way or includes multiple types of customers, prospects for commercial deployments dim.

The majority of microgrids that have been deployed to date in the United States—the world’s largest microgrid market—have relied upon a few major business models. For example, the most mature microgrid markets are systems deployed by owner financing and maintenance at universities, colleges, and hospitals. Likewise, stationary military bases—another semi-autonomous campus—typically rely upon standard government contracting vehicles such as energy performance savings contracts.

Purchase Agreement Innovation

Moving forward, I believe that the power purchase agreement (PPA) model will force innovation on the financing side of commercial microgrid deployments. A microgrid is far more complex than a rooftop solar PV panel. Nonetheless, as private developers become more confident in the ability of smart inverters and software controls to deliver economic dispatch of both internal and external generation and load, they will become more willing to take on the risk of a fixed price contract. Over the next 5 years, these private developer PPAs are expected to help establish the metrics by which microgrids will be judged thereafter. Companies such as Leidos are already plowing new ground on this front, factoring in the thermal energy benefits that are often key to making a microgrid viable.

Over the long term, utilities are most likely to bring this market truly into the mainstream. Whether they rate-base investments or choose to instead pursue this opportunity through their unregulated subsidiaries, their lower cost of capital can plug what currently exists as the biggest barrier to this market: a pool of funds to underwrite entire projects. Utilities serving rural communities that are not interconnected with a traditional utility distribution have been developing microgrids and putting them in the rate-base for decades. For example, approximately 100 such systems are operating in Alaska today.

However, rate-basing a microgrid in the lower 48 states is a different matter. That is why all eyes are still on the Illinois State Legislature as it considers legislation that would authorize Commonwealth Edison to rate-base six different microgrids serving a variety of customers, with the common goal of increasing the resilience of the entire utility’s distribution system.

Navigant Research will soon publish its Emerging Microgrid Business Models report, which reviews 10 approaches to developing microgrids today, ranging from a simple direct component sales approach to a comprehensive model being utilized by Siemens as well as PowerStream, the innovative municipal utility based in Ontario, Canada.

 

FERC vs. EPSA Ruling: A Win for Demand Response and Energy Storage

— February 1, 2016

Control panelWhen independent system operators (ISOs) and regional transmission organizations (RTOs) were structured over a decade ago, rate structures were primarily based on participation by conventional energy generation methods. During that time, new technologies and services like energy storage were not contemplated. The Federal Energy Regulatory Commission (FERC) Order 745, approved in 2012, called for grid operators to pay the full market price (known as the locational marginal price) to economic demand resources in the real-time and day-ahead markets, so long that it is cost-effective.

In short, Order 745 allows third parties (i.e., customers) to circumvent utility prices and provide flexibility via demand-side management. The United States Supreme Court (SCOTUS) made headlines on January 25 by upholding the FERC’s authority to regulate demand response (DR) programs in wholesale markets. Known as FERC vs. Electric Power Supply Association (EPSA), the Court reaffirmed in a 6-2 decision that FERC acted within its authority under the Federal Power Act when it issued Order 745, setting standards for DR measures and pricing in wholesale markets. This ruling is a big win for energy conservation service providers like EnerNOC, which saw its stock shares jump 65% midday after the ruling.

Battery Storage

The decision is not only big for DR, but has huge implications for resources at the edge of the grid like energy storage. Battery storage is gaining popularity among commercial and residential sectors as a cost-effective solution to reduce peaks, manage demand charges, and integrate renewables; Navigant Research forecasts that 102.4 GW of new distributed battery storage will be deployed from 2016 to 2025. As the new ruling could catalyze a sharp growth in the distributed storage industry, utilities and their customers have a unique opportunity to leverage it in a variety of ways to provide value on both sides of the spectrum.

Battery storage offers enriched DR options in a number of ways, one being the speed at which storage can be deployed. With storage, utilities are able to instantaneously declare DR events, rather than hours or a day ahead. Additionally, with advanced battery management systems, atypical events that occur on the grid can be responded to autonomously. Distributed storage as a resource is dependable in terms of its performance, power capabilities, and location, which further enhances DR. Batteries have a finite amount of energy they can provide, allowing grid operators to schedule other energy resources with increased certainty. Conventional DR is prone to under or overestimating customer behavior, which can lead to decreased system efficiency.

Rise of Variable Generation

DR and energy storage have significant implications when compounded with increasing penetration of variable generation (VG). A study conducted by the National Renewable Energy Laboratory found that the grid can accommodate approximately 30% of annual electricity demand from VG with “flexibility options” (namely changes in operational practices) that increase the penetration of renewable energy resources. As renewable penetration exceeds the 30% threshold, integration becomes increasingly difficult because conventional generators cannot readily moderate output, causing assets like wind and solar to be curtailed, which could raise system costs. Even with increased curtailment of conventional generation, renewables offset less fossil fuel generation, effectively decreasing their overall value. This creates a huge market opportunity for DR and energy storage with their ability to shift load patterns, solidify capacity, and increase grid flexibility.

SCOTUS made a monumental ruling for the cleantech industry, and there will be increased DR participation to come as a result. The market has already seen several DR/storage systems like Schneider Electric and Johnson Controls (both leaders in DR), and even partnerships like that of EnerNOC and Tesla. The nexus of energy storage and DR provides efficient, economical solutions for utilities and their customers. As a result, how energy is produced and consumed will drastically change, requiring rate-makers to be more versatile with evolving regulations.

 

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