Navigant Research Blog

Can Demand Response Help States Comply with the EPA’s Clean Power Plan?

— April 24, 2015

When the U.S. Environmental Protection Agency (EPA) released its draft Clean Power Plan (Section 111d) proposal last year, demand response (DR) was not specifically called out in any of the potential building blocks used to calculate state emissions targets. While it may reasonably be included in the End-Use Energy Efficiency block, some players in the DR space feel that a more explicit role is required to ensure that it gets the proper attention by states when they are developing their compliance plans.

Not Straightforward

To date, there has been no definitive analysis showing that DR can actually reduce carbon emissions. The case is not necessarily as clear as it is for energy efficiency, where more efficient equipment simply replaces less efficient equipment, leading to a straightforward engineering analysis of energy savings:

  • DR is not a permanent replacement, but rather, a temporary reduction in load in response to reliability or economic signals.
  • The reduction must be measured against some kind of baseline, for which there is no industry standard.
  • Some of the loads may be shifted to other times, so there may not be full kilowatt-hour (kWh) savings.
  • Some DR participants use behind-the-meter generation to respond, so depending on the fuel source, emissions could even increase instead of decrease.

Clearly, more analysis will be required to make states and the EPA comfortable with including DR in their plans.

Sniff Test

In order to take a first pass at the issue and get some initial thoughts into the comment record for the Clean Power Plan, the Advanced Energy Management Alliance contracted with Navigant in November 2014 to perform some high-level modeling and analysis to see if DR even passed the sniff test and is worth maintaining in the conversation. Navigant employs detailed market models that could perform such analysis on an hourly basis if a specific case should arise, but for this exercise, a simplified version was utilized to get an annualized view of the results.

Navigant looked at the PJM Interconnection, Electric Reliability Council of Texas (ERCOT), and Midcontinent Independent System Operator (MISO) markets, focusing on two different types of emissions savings: direct and indirect. Direct emissions reductions include peak load reductions through capacity and emergency DR programs and ancillary services markets like spinning reserves and frequency regulation where DR can participate. Indirect emissions consist of DR contributing to coal plant retirement decisions and allowing for increased levels of renewables penetration.

The analysis found that DR could directly reduce carbon emissions by more than 1% and that its indirect role in the economics of fuel mix and plant operations could result in reducing carbon emissions by an additional 1%.

Direct Emissions Reduction from DR Peak Load Reduction

(Source: Navigant Research)

Valuable Input

This emissions reduction potential is significant when compared to the EPA’s targets, which propose to reduce carbon emissions from fossil fuel power plants by 20% from 2012 levels by 2030. Perhaps the EPA will have heeded this input and will include DR more explicitly in its final rule expected in June. I am presenting these results at the Peak Load Management Alliance (PLMA) Spring Conference in Tucson on April 28, so we will continue to spread the message.


New York Details Its Vision for the Future of Energy

— March 2, 2015

On February 26, the New York Public Service Commission (PSC) released its long-awaited Phase 1 Order on its Reforming the Energy Vision (REV) proceeding. The order lays out the PSC’s vision for how the future retail electricity market in the state should operate to maximize efficiency, improve reliability, engage customers, and create clean, affordable energy products and services. I can’t cover the entire 328-page order in one blog, but I’ll hit on the major decisions that affect the current utility world order.

The biggest variable in the REV equation was whether the PSC would require an independent party to perform the function of the distributed system platform (DSP), the central role of REV. According to the order, the DSP’s functions include load and network monitoring, enhanced fault detection/location, and automated voltage and volt-ampere reactive (VAR) control. That list covers a lot of what the utilities currently do, so taking those tasks away from them would have caused a major shift in the market landscape. However, the Phase 1 Order outright supports utilities acting as the DSP as a way to minimize the redundancy of actions. This singular decision vastly limits the potential impacts to the state and the utilities. Utilities must be breathing a sigh of relief.

Metering Alternatives

A second thorny issue was whether utilities should be able to own distributed energy resources (DER) or whether DER should be the sole domain of the competitive marketplace. Many market players wanted to prohibit the utilities from competing with them when they might have a natural advantage in acquiring customers. Under the order, utilities will be able to own DER if they run a solicitation to meet a system need and they are able to show that competitive alternatives are inadequate or more costly than a traditional infrastructure alternative. They will also be able to invest in storage to the extent it functions as part of the transmission and distribution (T&D) system. This seems like a reasonable compromise that should work for most parties.

The last major component is advanced metering infrastructure (AMI). Earlier communications from the PSC hardly mentioned metering at all, so it was unclear how the final rule would play out. In fact, the Phase 1 Order does not mandate AMI deployment by utilities. Rather, the PSC prefers the term “advanced metering functionality” (AMF)—meaning that other technologies, including ones provided by third parties, may be able to achieve the desired functionality cheaper and more efficiently than AMI. It states that “each utility Distributed System Integration Plan (DSIP) will need to include a plan for dealing with advanced metering needs; however, plans that involve third party investment may be preferred over sweeping ratepayer funded investments.” This indicates that utilities should consider AMI alternatives before choosing a path forward.

Ticking Clock

As far as next steps, the utilities’ integration plans must be filed by December 15, 2015, so the clock is ticking. Phase 2 of REV will consider reforming the PSC’s ratemaking process so that utilities do not have disincentives to further developing DER. Utility income is tied to bond funds now, but they should depend more on creating value for customers and achieving policy objectives. A draft proposal is expected by June.

It was interesting trying to guess which way the PSC would fall on these and other major issues. Now the real fun begins: implementing the vision.


Adapting to the New Demand Response Landscape

— January 27, 2015

Demand response (DR) was first employed in the United States the 1970s.  At that time, DR was implemented as a component of the energy conservation focus of demand-side management (DSM) programs to encourage consumers to use less electricity during peak hours or to shift their energy use to off-peak times.  Utilities have run residential direct load control programs as forms of demand management and offered interruptible rates to commercial and industrial customers for many years.

Today, however, the electric grid needs resources beyond just meeting peak demand situations, requiring more flexibility and faster response.  A number of drivers point toward increased DR adoption by utilities and grid operators around the world.  The changing resource mix in electric grids globally is creating more potential for DR to play a pivotal role.  As coal and nuclear plants retire due to economic or environmental factors, clean replacements are needed that can be built in short timeframes.  Conversely, as large-scale intermittent renewable resources like wind and solar power fill in this gap, they require backup solutions when the wind is not blowing and the sun is not shining.

New Training Course

At the same time, new market types, including ancillary services such as spinning reserves and frequency regulation, are opening up to DR.  The concepts of resilience and microgrids have taken strong root along the Atlantic Coast following Hurricane Sandy in 2012, and DR will be an integral part of those developments.  The advent of grid modernization is also tied to this new view on how the grid should be designed.  With the proliferation of advanced meters that can record usage at very small intervals, more dynamic types of pricing can be applied down to the residential level.

To help utilities navigate through this changing landscape, the Peak Load Management Alliance has developed a series of DR training courses.  The next session, DR Program Design and Implementation, will take place from February 18 to 19, hosted by NV Energy in Las Vegas.  The 2-day course will first cover program development topics like DR program types; how to determine market potential; designing programs and managing portfolios of programs; and calculating cost-effectiveness.  The second day will delve into program implementation strategies and tactics such as staffing and operations; strategic outsourcing; technology architecture and integration; and evaluation, measurement, and verification.

A Visit to the NOC

NV Energy is a pioneer in testing out innovative DR program designs in an extreme climate.  The company has a diverse portfolio of programs that includes a range of applications, along with various flavors of direct load control, dynamic pricing, and DR in combination with energy efficiency programs.  The Las Vegas course will include a visit to NV Energy’s operations center, along with a first-hand look at its DR management system in action.

For utilities considering or being required to implement DR programs (which includes just about every utility today), this is a great opportunity to hear from industry experts and meet peers from across the country to exchange experiences and best practices.  For more information on the course, please click here.


Busy Start to 2015 for Smart Grid Companies

— January 22, 2015

Smart grid companies must have gotten their wishes granted during the holidays, because they are in a sharing mood to kick off the new year.  A burst of merger and acquisition and partnership activity shows that the ecosystem is growing and there’s enough room for everyone to get a piece of the bigger pie.

Trilliant and Innovari announced the completion of interoperability testing of the Innovari Interactive Energy Platform (IEP) and the Trilliant Smart Grid Communications Platform (SCP).  This combination enables utilities to improve operations and benefit customers with a shared communications infrastructure for smart grids.  The Innovari IEP provides automated demand response (DR) for commercial and industrial customers.  The Trilliant SCP complements the IEP with a two-way communications network to deliver grid situational awareness that enables real-time demand side management and the integration of distributed renewable energy resources.

Analytics and Engagement

Silver Spring Networks acquired longtime partner Detectent, which provides software to improve advanced metering infrastructure and utility grid operations, ensure revenue protection, and deliver enhanced customer engagement programs.  Detectent’s utility analytics solutions will be offered both as a standalone solution or powered by Silver Spring’s smart grid big data platform, the SilverLink Sensor Network.

Schneider Electric, meanwhile, announced two recent partnerships.  The first is a partnership with PlanetEcosystems to provide utility service providers with Efficiency Advisor, an integrated suite of software-as-a-service customer management offerings.  Combining Schneider’s Wiser Home Management system with PlanetEcosystems’ P-ECOSYS customer engagement platform, Efficiency Advisor will offer features like behavioral usage efficiency, home usage reporting, personalized recommendations, and an energy marketplace for customers to find contractors and financing options for energy efficiency programs.

Schneider’s second announcement involves a partnership between its European DR division, Energy Pool, and Hyosung, a South Korean industrial conglomerate, to offer DR in the newly opened South Korean marketplace.  Energy Pool will provide its DR expertise and manage operations, while Hyosung will tap into its network of industrial partners and provide IT support.

Just Couldn’t Wait

Often, companies will wait for the DistribuTECH conference to make big announcements about partnerships and new technologies, but these deals apparently couldn’t wait.  They’ll be discussed at this year’s DistribuTECH in San Diego, running February 3 to 5.  Last year, the theme at the conference seemed to be data analytics, as vendors showed how they can extract usable information from the plethora of data now available from meters and devices.  Based on these early announcements, it appears that the one-word summary for this year’s conference will be “interoperability.”

Now that the analytics are available, vendors are realizing that they likely can’t offer all possible analytical tools for utilities on their own, so collaboration will be necessary.  Whether that is through mergers and acquisitions or partnerships, I expect this trend to continue and am sure there will be more announcements at DistribuTECH from those who held back their surprises.


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