Navigant Research Blog

EnerNOC Rides the Tesla Wave

— May 13, 2015

Tesla’s announcement on April 30 of its stationary storage product has been treated like the biggest energy news since Edison invented the lightbulb. Elon Musk’s cult of personality has captured the world’s attention, and anything he says gets extreme coverage. That’s not to say that there is no substance behind Tesla’s developments or that they won’t lead to changes in the industry. At the very least, the attention raises the profile of the normally staid energy world, which should benefit all players in the space.

One company that caught the Tesla wave was EnerNOC, which announced a partnership with Tesla’s new commercial and industrial storage offering. EnerNOC’s stock jumped over 20% after the news hit. That’s the short-term bump that such notoriety can lead to. I spoke with Micah Remley, EnerNOC’s senior vice president of product, to learn about what the company sees as the real benefits of this relationship.

Enhanced Intelligence

Basically, Tesla will provide the storage hardware to a facility and EnerNOC will provide the software smarts to tell the unit when to charge or discharge in an optimal manner. The software does this by taking in signals from inside the building and from external markets and figuring out how to gain the most financial benefit on an ongoing basis. Remley said that the Tesla unit has some smarts as a standalone unit, but the gains from EnerNOC’s software should outweigh the costs. When asked about the potential economic impact on EnerNOC’s business from this relationship, Remley said it is too early to measure as the partnership is still in its pilot phase. But it does not appear that this will add significantly to the bottom line in the near term.

I spoke with EnerNOC’s CEO Tim Healy at the company’s analyst conference back in November 2013, when the company launched its foray into the energy intelligence software space. I asked him if he planned on getting more into the hardware side with topics such as combined heat and power, solar, and storage; Healy said EnerNOC is clearly focused on the software side of things. It appears the company has found a way to keep to that mantra while not letting the proliferation of distributed energy resources pass it by.

Back to Earth

EnerNOC struck a similar deal with SunPower in the solar space in March that didn’t get nearly as much attention as the Tesla deal. From EnerNOC’s standpoint, things like solar and storage are just new endpoints that can be integrated into its existing software that has mainly been developed for demand response purposes. This move represents an important diversification strategy as competitors offer holistic solutions, customers demand central control systems for all of their various resources, and regulators in states like New York and California attempt to add value to all types of new technologies and market structures.

EnerNOC’s stock has come back down after the Tesla hype, but the partnership strategy should benefit the company in the long term.


Waiting for the Supreme Court’s Call

— April 28, 2015

Many are waiting for the Supreme Court to decide whether it will take up the case on the Federal Energy Regulatory Commission’s (FERC’s) Order 745 on demand response (DR) compensation, possibly by the end of April. I thought it would be worthwhile to take a look at the contingency or stop-gap plans that some of the affected regional transmission organizations (RTOs) are contemplating, particularly for the capacity markets where the vast majority of DR participation takes place. PJM started the process several months ago; the New York Independent System Operator (NYISO) began a couple months ago; and the Independent System Operator of New England (ISO-NE) just released its proposal last week. All of them start from similar basics, but there are differing details that may affect the effectiveness of each one.

PJM: Laying the Groundwork

PJM laid the groundwork first and came up with a straightforward proposal whereby the DR would be moved to the demand side of the reliability pricing model (RPM) capacity market. The load-serving entity (LSE), which provides the retail electricity supply to customers (either a utility or a competitive supplier), would reflect the DR in its demand bid. This would lower the total demand in the market, leading to the same price effect as if the DR had bid into the supply stack.

Integration of DR Bids with RPM Demand Curve

(Source: PJM Interconnection)

In theory, this approach gets around the FERC jurisdictional issue in the court case because it would be retail entities bringing the DR to the market instead of direct wholesale market participation. The concern from DR providers is that this structure adds an extra layer of administration between the customer and the market, since the DR providers wouldn’t be able to bid in directly (unless they were an LSE) and they would have to work through the LSEs. That relationship may necessitate extra legal documentation. Plus, some LSEs may not be motivated to encourage DR and could bog it down, leading to a reduction in the amount of DR in the marketplace. PJM even submitted this proposal to the FERC to be proactive and have it in place should the court force its hand, but the FERC ruled that it was premature instead of proactive and should not be formally introduced until the court verdict is clear.


NYISO basically used the PJM proposal as a starting point and built upon it. After getting feedback from market participants about the drawbacks of the PJM structure, NYISO added a twist in which the LSE is basically just a pass-through mechanism for the DR to reach the market, while the DR providers are still the contracting agents that register the customers with the NYISO. This adjustment eases some of the perceived constraints from the PJM model, but there are still a lot of details that need to be worked out in terms of bidding and how DR providers can continue to participate in the NYISO stakeholder process.

ISO-NE Approach

ISO-NE had been pretty quiet on the matter until April 17, when it released its contingency plan. It took a different path than NYISO to try to address some of the shortcomings of the PJM approach. It still relies on the LSE to administer the DR, but it purports to provide more incentive to the LSEs to do so by changing the cost allocation methodology for capacity costs from a fixed charge to a performance charge reflecting the actual consumption of customers during scarcity conditions. LSEs consuming less than their allocated share of capacity would see their charge go down; the converse is true for those consuming more. In theory, this model incentivizes LSEs to reduce their load during these times; reality could prove otherwise if none of the large LSEs feel the risk outweighs the potential benefits.

There you have three different approaches to address the same issue. Perhaps none of them will be necessary if the Supreme Court ultimately vacates the lower court’s ruling, but in the meantime, many smart people have spent many hours getting ready for the worst-case scenario.


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.


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