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Demand Response


SOTM 2019 Webinar Series

August 08, 2019
60 minutes with CPower Experts. Energy Insights to Plan Your Year. At CPower, we know that running your organization’s…

Webinar: Industrial Manufacturing Demand Response

August 05, 2019
In this webinar, CPower’s experts discuss the energy-related issues affecting the US manufacturing industrial sector and explore demand-side energy management options aimed to help manufacturers offset soon-to-be rising energy costs without sacrificing their productivity.

Navigant: Utility Demand Response

July 09, 2019
This white paper highlights critical insights for utilities into the implementation of future customer-focused DR programs, given the rapidly changing and distributed energy grid. Utilities with existing DR programs that are either underperforming or otherwise failing to yield desired results may look to the considerations and case studies to strengthen their existing DR portfolio and meet customer needs.

Seasonal Readiness 2019

May 22, 2019
Are you ready for the 2019 demand response season? Our program information and On Demand Webinar resources will help make you successful in your programs in 2019. Here, you'll find program information, key dates (like communication drills), your CPower contacts, market information, dispatch information and more.

Why doesn’t Texas have a Capacity Market?

April 10, 2019

When the Electric Reliability Council of Texas (ERCOT) established Texas’ deregulated energy market in 1999, it had several very Texan ideals in mind.

For starters, the market’s architects sought good old-fashioned economic competition to keep electricity prices stable and the state’s grid reliable.

They also settled on another battle-tested Texan value concerning its energy market: They wanted to be completely different from New York…and California, New England, and PJM for that matter.

And so it came to be that Texas would establish an energy-only market without a forward capacity market. In doing so, ERCOT became the only deregulated energy market in the US that is NOT overseen by the Federal Energy Regulatory Commission (FERC).

In the two-plus decades since ERCOT’s formation, naysayers in and out of Texas have been watching the Lone Star State with skeptical eyes, waiting for the perfect storm when a lack of forward-procured capacity proves fatal to grid stability.

Every time the reckoning seems imminent (as it did in the Summer of 2018) the ERCOT market holds strong, bending at times but never breaking. Now, many former naysayers around the US are wondering if perhaps instead of messing with Texas, other deregulated energy markets should be learning from the Lone Star State.

That Texas doesn’t have a forward capacity market is one of the market’s signature design features.

Consider a market like the Pennsylvania-Jersey-Maryland (PJM) Interconnection. To keep its grid reliable, PJM maintains a forward capacity market (the largest in the world) whereby the capacity needed to meet peak-demand is procured three years in advance of its delivery day.

Using this model, PJM procured a comfortable reserve of about 21% above its reserve target in its latest capacity auction. The onus of paying for this surplus of capacity falls to ratepayers in the market, who pay for PJM’s reserve margin with higher capacity prices/demand charges.   

The ERCOT market, in contrast, aims to keep costs incurred by its ratepayers at a minimum by avoiding what they see as an unnecessary surplus of capacity.  

Instead of a capacity market, ERCOT maintains a capacity reserve margin, calculated by subtracting the projected peak demand on the grid from the total capacity generation available in Texas.

ERCOT’s target reserve margin hovers around 13.75%, lower than PJM’s 15.8%–considerably cheaper for Texan ratepayers, too.  

Back to the original question of why doesn’t ERCOT have a capacity market. The answer is simple and decidedly Texan: Economics. Economics. Economics. (and a little desire to be different).

The Summer of 2018: ERCOT’s Proving Ground

For years, skeptics have watched the ERCOT grid, wondering when the right set of circumstances would finally expose Texas’s lack of capacity market for its inability to maintain grid reliability.

Last summer, it looked like the skeptics would finally have their day.

A shrinking reserve margin, record-setting peak demand, and a near-record heat wave pushed the ERCOT grid to its limits, but the grid held.  

In September 2018, the Public Utility Commission (PUC) of Texas issued a 45-page Review of Summer 2018 ERCOT Performance, officially summarizing how the grid functioned against daunting conditions.

That the lights stayed on in Texas last summer boosts ERCOT’s belief that an energy-only market relying on economic competition as opposed to government mandate can maintain sufficient resources to keep the grid stable and avoid turning to emergency, out-of-market measures.   

Much of the energy industry has taken note, too.

The R Street Institute, a public policy research organization based in Washington D.C., noted “the Texas market is working, as consumers and producers find innovative ways to reduce costs and enhance service quality.”

Demand Side Management to the Rescue

The PUC’s performance review also noted the integral role demand-side and distributed energy resources (DERs) played in keeping ERCOT’s grid reliable during the Summer of 2018. There were no rolling outages or blackouts.   

Despite not experiencing a demand response event during this past summer, ERCOT’s ongoing investment in ancillary services and recent updates on how they are procured and dispatched have paid off.


This post was excerpted from the 2019 State of Demand-Side Energy Management in North America, a market-by-market analysis of the issues and trends the experts at CPower feel organizations like yours need to know to make better decisions about your energy use and spend.

CPower has taken the pain out of painstaking detail, leaving a comprehensive but easy-to-understand bed of insights and ideas to help you make sense of demand-side energy’s quickly-evolving landscape.

Get Your Copy

Demand Response in New England: The more things change…

ISO-NE’s implementation of its price-responsive demand construct has led to several changes in its demand response programs.

Three key changes for 2019:

  • DR programs are now dispatched based on economic (instead of emergency) conditions.
  • DR is now considered fast-acting DR and must be dispatched within 30 minutes of the grid’s call for curtailment.
  • DR resources can be offered into both day-ahead and real-time energy markets.

It may seem like the market has changed drastically and therefore demand response participation in New England will also be strikingly different than it was in the past.  

While the former may be the case, the latter really isn’t.

The fundamentals of demand response participation in New England have not changed that much from the customer’s perspective. Here’s why:

  • DR programs are still dispatched with a 30-minute notification window.
  • Because the economic conditions that trigger DR under PRD tend to coincide with emergency conditions, there isn’t expected to be an increase in the number of events called in 2019 under the new construct compared with previous years.  
  • Audits (tests) proving performance are the same as they were in 2018.

Capacity prices in New England have been trending downward in recent years.

While lower capacity prices mean lower payments for DR curtailments, they are also a sign that New England has procured adequate capacity resources. This means it is probable that there will be fewer events called in the coming years and that those events are not likely to last as long as events in previous years when capacity prices in New England were higher.   

Demand Response Programs in New England

ISO-NE offers the following demand response programs:

Active Demand Capacity Resource (ADCR) is a demand response program in which participating loads are dispatched when wholesale electricity prices in New England are exceptionally high.

Launched in June 2018 as part of ISO-NE’s price-responsive demand construct, ADCR replaced the Real-Time Demand Response Program (RTDR).

Passive [On-Peak] Demand Response rewards participating organizations for making permanent load reductions.

Unlike active resources, On-Peak resources are passive, non-dispatchable, and only participate in ISO-NE’s Forward Capacity Market. Eligible behind-the-meter resources include solar, fuel cells, co-generation systems, combined heat and power systems (CHP), and more.

Passive Demand Response participants offer their reduced electricity consumption into the market during both the summer and winter peak hours.

Utility Demand Response Programs

Connected Solutions–National Grid, Eversource, and Unitil are working to lower the amount of total energy our community uses during the summer months when demand for electricity on the grid is at its highest (peak demand).

To help keep their grids healthy and reliable, these utilities now offer the Connected Solutions demand response program that pays businesses to use less energy during peak demand periods.

The rules may be changing in the New England energy market, but for the commercial and industrial organization gearing up for the summer season…demand response is the same sport as it has always been.


This post was excerpted from the 2019 State of Demand-Side Energy Management in North America, a market-by-market analysis of the issues and trends the experts at CPower feel organizations like yours need to know to make better decisions about your energy use and spend.

CPower has taken the pain out of painstaking detail, leaving a comprehensive but easy-to-understand bed of insights and ideas to help you make sense of demand-side energy’s quickly-evolving landscape.

Get Your Copy

PJM: A Look Ahead to Summer ’19 and Beyond

April 09, 2019

Summer 2019 is right around the corner, which means another season of PJM’s Emergency Capacity demand response (DR) program is set to kick off. This 2019/2020 marks an important pivot point for DR in PJM. With DR enrollment underway, let’s take a look at some things to expect this summer. 

2019 Summer Outlook

Weather-wise, early indications point to the PJM region experiencing normal to mild summer temperatures. That’s good news for DR customers in Emergency Capacity but may be challenging for peak shavers to accurately predict PJM’s 5 CP (Coincident Peak) hours. The weak El Nino climate is not expected to have much of an impact, although there’s a good chance that the historically wet 2018 season will carry over to 2019. So don’t put away those rain slickers just yet!

Capacity-wise, PJM forecasts summer peak load of 151,358 MWs. Unlike in Texas, where the grid operator ERCOT (Electric Reliability Council of Texas) is forecasting a reserves situation that make summer emergency events likely, the PJM region at this point seems to have adequate reserves. As we learned during the 2014 Polar Vortex, though, nothing is completely certain when it comes to expected supply and demand. Here’s hoping the summer weather forecast proves to be right.

Goodbye Base and Summer Capacity, Hello Capacity Performance— and Seasonal Aggregations

June 2019 will mark the final season of PJM’s summer-only DR programs. PJM retired the Limited and Summer Extended DR programs after the 2017/18 delivery year, and now will retire the Base Capacity program at the conclusion of the 2019/20 delivery year.

This will usher in the long-talked-about Capacity Performance (CP) DR program as the lone DR program available, starting next year for the 2020/21 delivery year. As you probably know (and as we discussed in last year’s white paper on the myths around CP), the CP program required DR participation and compliance year-round, not just during the summer. As originally designed, CP DR customers would have to participate with one load reduction value for the entire year. To many, this has caused far more problems than it solved, as many DR customers feared having their participation levels drastically reduced — or even dropped from the program entirely — due to concerns over their inability to participate and comply in the winter.

Fortunately, PJM and the FERC (with a little help from CPower Market Development and others, advocating on our customers’ behalf) may have found a way to put those concerns to rest.

The FERC (Federal Energy Regulatory Commission) recently approved a PJM filing that will now allow DR customers to participate in CP with two different summer and winter seasonal load reduction values. Of course, there’s a catch. Participating with separate summer and winter values is contingent upon the customer’s curtailment service provider (CSP, i.e., CPower) being able to offset its seasonal load to create “CP Aggregations.”

How does that work? Let’s take two customers, Alpha Amalgamated Alloys and Beta Better Ball Bearings. Each has participated in summer-only DR for years. Now, however, they have to make year-round commitments, and they’re stuck.

Enter the new rule and their CSP, CPower. CPower works with each to determine what each can contribute for summer and, separately, for winter. Alpha determines that they can reduce 5 MW in the summer but only 2 MWs in the winter. Beta determines that they can reduce 1 MW in the summer but 4 MWs in the winter. And they’re both in the same utility zone within PJM.

Under the rule as originally created, Alpha would be faced with having to curtail only 2 MWs in the summer, when they used to be able to curtail—and monetize—5 MWs. Meanwhile, Beta would be unable to monetize their additional 3 MWs of now-required load in the winter. That could change the desire to participate in Emergency Capacity DR for these two long-time customers.

The new rule, however, allows their CSP to aggregate (or combine) their reductions to create a CP zonal aggregation of 6 MWs year-round. Their combined summer reductions and winter reductions balance each other out and comply with the new CP requirements. Each continues to benefit from DR participation in PJM. 

This program rule change, thankfully, allows more flexibility and opportunity for PJM’s DR customers to participate as Emergency Capacity resources (which PJM always needs). This assumes, however, that their CSP has the market position and a diverse portfolio to successfully manage these DR CP programs.

Shameless plug: CPower, of course, has the capability to generate zonal CP aggregations across all PJM zones and all customer types. We’ve worked hard to not only build ourselves into the top curtailment aggregator in PJM; we’ve also advocated tirelessly before PJM to create this opportunity for our customers to ensure that CP doesn’t negatively impact PJM’s vital electric reserves. In this way, barriers become opportunities, and everyone wins.

What to Look Out For

PJM has pushed back their next Base Residual Auction (BRA) for the 2022/23 delivery year from May, 2019, to August, 2019 and the possibility still remains that it could get pushed back again until early Spring 2020. This will allow for some RPM rule changes to be implemented. If you’re interested in future capacity prices and DR availability, stay tuned, as the results for that auction won’t be known for a few more months.

PJM stakeholders are discussing potential changes to the mandatory DR test even that occurs each summer if there is no actual emergency event called. Some topics of discussion are: increasing the test event to longer than one hour; compensating test event compliance with emergency energy payments; PJM scheduling the test event instead of the CSPs; and possibly a mandatory winter testing provision. Nothing’s set in concrete yet, and CPower will keep you up-to-date as the discussions move forward.

Just Released: 2019 State of the Market

Finally, CPower has released, “2019 State of Demand-Side Energy Management in North America.” This is an invaluable resource filled with analysis and commentary from CPower’s market experts (including yours truly). It covers all regions served and supported by CPower in the U.S. and Canada and will be an important source of information for DR customers and partners regionally and nationally. Download your guide here.

If you have any questions about goings-on in PJM now and in the future. don’t hesitate to reach out to the PJM team. As always, we’re here to help.