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Has California finally solved “The Duck Curve?”

April 10, 2019

California experiences a daily spike in energy demand in the early evening when renewable sources like solar go offline and residents come home from work and increase their energy consumption by flipping on their air conditioning, turning on their lighting, doing laundry, charging electronic devices, and engaging in other energy-consuming activities.

When charted on a graph (see picture), the shape of California’s daily electrical consumption resembles a duck. Analysts have noted the duck’s belly is getting fatter with each passing year, meaning the evening net load ramp when flexible resources are needed to account for the spike is becoming more extreme.

A Steady Diet of Storage

The duck’s belly may not get fatter in 2019, but it’s still going to be heavy.

To help alleviate grid stress associated with evening load ramp, CAISO is developing a load-shifting product under the third phase of CAISO’s Energy Storage Distributed Energy Resource (ESDER) that would be the state’s first product that will pay a resource to consume energy to soak up excess generation during negative pricing periods.

CAISO’s load-shift program embodies California’s desire to bring clean resources to the forefront of grid reliability by storing excess clean energy and making it available for future use.

The program, championed by the California Energy Storage Alliance (CESA) among other energy storage companies, also aims to reduce the number of solar curtailments needed to offset the ill effects of negative pricing caused by a large solar surplus on CAISO’s system.   

The two big questions on the minds of organizations that have implemented or are thinking of implementing energy storage are:

  1. When will the CAISO’s load shifting product be available for participation?
  2. How will these storage resources be valued in the wholesale market?

The short answer to the first question is the program is currently going through the FERC approval process and is scheduled to go into effect in November 2020.

As far as how storage will be valued in the wholesale market? It’s too early to tell right now, but expect California to continue to work to provide value for all the services storage can provide.


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 of the 2020 book

Is Global Adjustment in Ontario here to stay?

The Global Adjustment was introduced in 2006 to help Ontario cover the difference between electricity’s market rate and the contractually higher rates the provincial government had agreed to pay new generators in an attempt to stimulate private investment in Ontario’s generation system.

All Ontario electricity customers pay global adjustment to cover the cost of the province’s new electricity infrastructure and conservation programs, which ensure adequate long-term electricity supply.

With the passing of the Green Energy Act in 2009, GA charges spiked and have been on the rise ever since.

A 2015 report by auditor-general Bonnie Lysyk concluded that Ontario ratepayers had paid $37 billion more than necessary from 2006 and 2014 and will spend an additional $133 billion by 2032 due to inflated GA charges.

Whether GA charges are necessary is a hot topic of a debate whose arguments tend to fall, like most public squabbles on energy policy in Ontario, along the lines of political party loyalty.  

What’s not up for debate is the fact that GA charges can account for up to 80% of an organization’s electricity bill.

The Industrial Conservation Initiative (ICI)

Introduced by the Government of Ontario in 2011, the Industrial Conservation Initiative (ICI) is a form of demand management that allows organizations to reduce their GA costs by reducing their demand during the five periods when total demand on the Ontario grid is at its peak.

Although all electricity consumers pay Global Adjustment, only Class A customers–those with an average monthly peak demand greater than 1 MW (or with 500 kW if the company has NAICS codes commencing with the digits “31”, “32”, “33” or “1114”) during an annual base period from May 1 to April 30–can participate in the ICI.  

In April 2017, the ICI threshold was lowered to its current requirement (Ontario Regulation 429/04). Previously, the threshold had been much higher (minimum 5 MW in 2016), which excluded large manufacturing and industrial sectors from participating.  

This 2017 change, which increased the number of large consumers who could participate in the ICI and therefore reduce GA charges, has impacted electricity prices significantly in Ontario.

The ICI’s unintentional cost shift

According to the Ontario Energy Board (OEB), the Global Adjustment has grown from CA$700 million in 2006 (8% of the province’s total electricity supply costs) to CA$11.9 billion in 2017, accounting for 80% of Ontario’s electricity supply costs.

During this time of GA growth, peak demand in Ontario has dropped due in large part to ICI participants reducing peak load contributions, decreasing their GA charges in the process.  

In 2017, when the ICI drastically lowered its minimum peak load requirements, participants reduced their consumption by 42% during peak conditions.

While reduced peak demand brought through the ICI has proven to be healthy for the grid, the initiative has also given birth to an unintended consequence Ontario policymakers realize must be addressed.

In its report, the OEB concluded that the ICI has brought about an unintended shift of electricity costs recovered through the GA from large volume consumers to households and small businesses.

The burden of costs the GA was established to alleviate, it turns out, has hardly been alleviated. Instead, the costs have merely been shifted from large consumers to small.

In 2017 alone, the OEB asserts that the ICI shifted CA$1.2 billion in electricity costs to households and small businesses, thereby increasing the cost of electricity for households and small businesses by 10%.

The OEB concluded that the ICI as currently structured “is a complicated and non-transparent means of recovering costs, with limited efficiency benefits.” The initiative “does not allocate costs fairly in the sense of assigning.”

Like much of Ontario’s energy policy, the future of the ICI is not yet set. There are talks for and against a flat rate for GA to be paid all consumers. There are debates on a new restructuring of the ICI altogether.

Expect the new government to have its hands full examining what, if anything, can be done about GA charges and the ICI in 2019 and beyond.

Organizations, large or small, looking toward offsetting high GA costs in the future would be wise to keep abreast of any changes to the ICI, because they may have a profound impact on demand-side energy management strategies currently in the works.


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

The Ontario Market: a (very) brief history

By the early-1990s, Ontario’s energy grid faced dire reliability and economic concerns.

Many of the nuclear generation plants powering the province had been built in the 1970s and were starting to prematurely show their age, declining in efficiency and reliability.

More recently-built nuclear stations had riddled Ontario Hydro (Ontario’s then publicly-owned and lone electric utility) with enormous debt.

In 1992, the situation worsened when a downturn in the Canadian economy and falling demand caused electricity rates in the province to rise by 40%.

The following year, the Ontario government stepped in, freezing energy prices. They would remain frozen for the next 10 years.

In 1999, Ontario’s energy market took its initial steps into deregulation. That April, Ontario Hydro was restructured into five separate companies, including the Independent Market Operator (later named the Independent Electricity System Operator or IESO, which still serves as Ontario’s grid operator today.)

On August 14th, 2003 the lights went out across Ontario when the Northeast Blackout caused more than 50 million people in southeastern Canada and eight northeastern states to lose power for two days.

It was the largest blackout in North American history.

One year after the blackout, the Ontario Power Authority (OPA) was established and immediately tasked with assessing the long-term adequacy of the grid’s resources. The OPA, which would eventually merge with the IESO in 2012, was also mandated with removing coal from the province’s supply mix.

In an attempt to stimulate private investment in new generation beginning in 2005, Ontario began offering long-term, fixed-price contracts at above-market rates to new generators.

To cover the difference between electricity’s market rate and the contractually higher rates being paid to new generators, Ontario introduced the Global Adjustment in 2006. That same year, the Renewable Energy Standard Offer was established, offering fixed-rate 20-year feed-in tariffs (FITs) for solar, hydro-electric, wind, and biomass renewable projects.

The Green Energy Act was passed in 2009 with the aim of attracting new investment, creating green jobs and providing Ontario with clean, renewable energy.  

To help consumers shoulder the costs of Ontario’s transition to a greener, modern electricity system, the government introduced the Ontario Clean Energy Benefit (OCEB) in 2010. The benefit provided eligible consumers a 10% rebate on applicable electricity charges and taxes.

The OCEB ended in 2015. That fall, the Ontario Energy Board raised electricity prices, burdening Ontario ratepayers with electricity bills that were among the highest in Canada.

In 2018, while campaigning for the Progressive Conservative party, current Ontario Premier Doug Ford promised to reduce energy prices in Ontario by 12%.  

As of this writing, Premier Ford has yet to present an official energy plan outlining an approach to keeping his campaign promise. The provincial government has announced the cancellation of 758 renewable energy contracts awarded by the previous assembly.

What does this history tell us about the Ontario energy future? We examine that question in this article about the future of Global Adjustment in the province.


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

How to hedge against Load Resource proration in ERCOT

Of the demand response programs that ERCOT offers, Load Resource offers the most lucrative potential–particularly during the summer months when demand on the grid is at or near its peak.

Simply put, ERCOT’s tight reserve margin is brought about by diminished supply and growing electrical demand, which in turn causes high energy prices in Texas during the summer.

These high prices are welcomed by participants in the Load Resource program, which pays organizations for being available to curtail their energy loads when called on by the grid operator.

The LR program attracts a lot of interest, so ERCOT places a cap on the total amount of Load Resource it buys, typically ranging from 1,400-1,750 MW.

Suppose the cap is projected to be 1,500 MW.

If more than 1,500 MW of Load Resource offer into the market, ERCOT prorates ALL of the MWs down to its 1,500 MW threshold.

Suppose 3,000 MW offer into the market as part of the LR program. ERCOT can only buy 1,500 MW of load resource. In this case, an organization that could otherwise curtail 10 MW would only be awarded five and be paid for those 5 MW. Another organization that could contribute 4 MW will only be awarded two and so forth until the total sum of all LR participants is 1,500 MW.  This example illustrates 50% proration.

Historically, LR proration in the ERCOT market hovered around 90%, meaning a 10 MW offering is prorated down to 9 MW.

That started to change in 2017 when proration worsened as more resources sought to enter the market. In 2018, proration averaged about 50%, irritating many participating organizations accustomed to earning more revenue for being available to curtail if needed.

Fixed vs Index Load Resource Offerings

The standard Load Resource offering is indexed based on dynamics in the market, grid conditions, and weather conditions.

These conditions vary in their extremism and therefore cause the price ERCOT pays for load resources to fluctuate.  

Historically (at least before 2018) the Load Resource program has offered participants a potential windfall to be available when the grid was most in need.

Now, proration is threatening that windfall for a lot of LR participants.

That there are a lot of participants in the LR program is the reason why proration is rising and earnings in the program are diluted.

Enter fixed LR.

Fixed LR takes proration out of the picture for participants by locking in an average, weighted return for a specified period of time. Locking into a fixed LR contract can guarantee a more attractive rate of return than the historical indexed LR average.

The averaged indexed LR return was between $6 and $7 per MW/hour in 2017 and around $9.50 in 2018.  Heading into the 2019 summer season, fixed LR offerings are being secured with a 20-30% return above the indexed average.

To Fix or not to Fix?

Fixed LR tends to appeal to the more risk-averse participant compared with standard indexed LR. The former is more stable, the latter essentially a bet that the summer will include a couple of days when LRs driving contributors present a blowout scenario.

As any wise investor will attest, a balanced portfolio has the best chance to succeed.

Consider breaking your load into increments and determine a strategy to hedge against those different scenarios with a combination of fixed and indexed LR.

Lock in certain rates above the historical averages with fixed LR and position yourself for a nice reward during the few scorching days during the summer and extremely cold days during the winter with indexed LR.


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

Why doesn’t Texas have a Capacity Market?

This post was excerpted from the 2019 State of Demand-Side Energy Management in North America.
To get a breakdown of the February 2021 Winter Event in Texas, click here.

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

New England’s Emerging Hybrid Grid

Currently, there are two developmental shifts taking place in New England concerning the electricity grid.

  1. The grid is shifting from conventional generation to renewable energy.
  2. The grid is also shifting from centrally dispatched generation to distributed energy resources.

What was formerly a traditional power system is becoming a hybrid system with electricity needs met by both conventional resources (natural gas-fired generators dependent on just-in-time deliveries of fuel) and large-scale renewable resources (weather-dependent wind and solar) connected to the regional transmission system.  

New England’s hybrid system will also include thousands of small resources connected directly to retail customers or local distribution companies.

As this new hybrid grid emerges, maintaining reliable power system operations will become more complex due to new resources facing familiar constraints on energy production.

The Significance of New England’s Changing Fuel Mix and Evolving Energy Policies

In its State of the Grid 2019 presentation, ISO-NE provided a concise take-a-way statement:

“[The] Grid is holding steady on a strong power foundation, but the power system is changing and vulnerabilities are growing.”

Let’s first examine the grid’s strong fundamentals that have led to reliable power being supplied to the region over the last two decades.

ISO-NE has identified four key ingredients for the grid’s continuous reliability:

  1. Reliable Operations–Record cold, heat, demand, and major equipment outages have tested the grid in recent years. The grid has held.
  2. Robust transmission system–Big investments in system upgrades have increased grid efficiency and enhanced competition.
  3. Resource adequacy–New England’s Forward Capacity Market continues to attract and retain the capacity required to meet demand.
  4. Established, collaborative decision-making process–The ongoing collaboration between the ISO, market participants, state officials, and consumer advocates over the last 20 years has found and will continue to find solutions to the region’s energy challenges.

Now, let’s examine the grid’s potential vulnerabilities. ISO-NE has identified two areas of concern:

  1. Energy security risk–As the NE fleet shifts from power plants with stored fuels to resources that depend on weather or just-in-time fuel deliveries, there is growing concern that adequate capacity will be available throughout the region on a year-round basis.
  2. Shifting policy priorities are challenging competition in the market--NE’s competitive market has delivered reliable energy at fair market prices for the last 20 years. Competition has helped lower wholesale electricity prices while spurning investments of more than $16 billion in cleaner power plants and resources that reduce demand.

That said, the region’s individual state initiatives and mandates aiming toward clean energy goals have created a need for markets to be adapted to sustain the benefits of competition.


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.

What has PJM learned from the Polar Vortex?

On January 2, 2014, a sudden stratospheric warming caused a breakdown of the polar vortex, a semi-permanent low-pressure system of cold polar air that helps the jet stream maintain a roughly circular path as it travels around the globe.

A healthy polar vortex keeps the jet stream in line, which in turn keeps the cold air up north and the warm air down south.

An unhealthy polar vortex allows the jet stream to break apart, allowing the Arctic’s frigid air to escape southward as it did in 2014. The 2014 Polar Vortex (officially the 2014 North American Cold Wave) led to record low temperatures in the US and caused PJM’s grid to face dire reliability concerns.

In the wake of the 2014 Polar Vortex, PJM established a new market design to better procure resources when the grid is stressed due to extreme weather.

Five years later, the PJM grid would again be challenged when a weak polar vortex led to temperatures in the US plummeting to record lows, including -23 degrees in Chicago in late January 2019.  

That the PJM grid maintained its reliability in the winter of 2018/19 is a sign that recent market changes are working as designed.

Let’s examine those changes with an eye on how commercial and industrial organizations in the region can leverage their existing energy assets and achieve demand-side energy management success.

What did Winter 2014 Teach PJM?

On January 14, the coldest day of winter in 2014, 22% of PJM’s generation was unavailable to meet consumer demand. PJM knew they had to take action to ensure the grid had enough capacity in the future to meet the most daunting and coldest circumstances.  

“To ensure reliability, we’re doing everything humanly possible. If the lights aren’t on, nothing else matters.”

–Terry  Boston, PJM President and CEO  

2014 PJM Annual  Report

To guard against future outages like the ones experienced in 2014, PJM proposed to the Federal Energy Regulatory  Commission (FERC) a redesign of the region’s Reliability Pricing Model (RPM), the capacity market that ensures long-term grid reliability  by securing the appropriate amount of power supply resources needed to meet predicted energy demand three years in the future.

PJM’s Transition to Year-Round Demand Response (DR)

One of the more significant changes PJM implemented involves a transition to demand response programs that require year-round participation.   

PJM’s two emergency capacity demand response programs available in 2019, Base Capacity and Capacity Performance, each reward year-round participation from its participants.

Base Capacity, however, differs from Capacity Performance in that it requires performance in the summer months of June through September, but can also reward for responding to dispatch throughout the year. 2019 will be the final year PJM offers Base Capacity.

These new programs replaced the legacy DR programs PJM previously offered until the end of the 2017/2018 program–Limited DR, Summer Extended DR, and Annual DR.  

How has Capacity Performance affected grid reliability?

The short answer is PJM’s grid is doing just fine having shifted to Capacity Performance.  

In an analysis on its system performance during the “bomb cyclone” cold snap from Dec. 28, 2017, through January 7, 2018 (the region’s coldest stretch since 2014), PJM confirmed its grid performed well, with excess resources available on days when temperatures were the most frigid.

But that doesn’t mean PJM doesn’t see room for improvement in 2019.


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.

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Is Peak Shaving more Lucrative than Demand Response in PJM?

Peak-shaving, essentially the practice of an organization reducing its demand during times of peak grid stress to lower its capacity charges, is part of what the Federal Energy Regulatory Commission is considering as the agency examines PJM’s annual capacity construct.

In a June 2018 proposal, PJM stated it hoped to reduce its capacity market demand curve by including peak shaving among the variables it considers when developing its load forecast.  

To do this, PJM would have to adjust its current forecasting model, which involves identifying gross load for a delivery year and establishing a forecast that includes economic, weather, and end-user changes, but excludes peak shaving as a variable.

PJM believes their proposed model will provide a more holistic view of the grid and its potential need for resources to maintain the balance between supply and demand.

Opponents are concerned whether PJM’s proposed methods for integrating peak shaving as a variable in forecasting its load are underdeveloped and will ultimately provide an accurate forecast.

They may have a point.

PJM’s proposal states among its outstanding issues that accounting for existing peak shaving activity relies on entities providing PJM with historical peak shaving activity and that currently there is no established best practice for obtaining this crucial data.  

Is Peak Shaving Right for Your Organization?

Given all this uncertainty around peak-shaving in PJM, it’s a fair question to ask if the practice is right for your organization.

Since no two organizations are alike, the answer to that question will naturally vary from one organization to the next.

Consider that an organization involved in peak shaving will likely curtail for about 30 hours in a single summer in an attempt to time their curtailment with the hours PJM’s grid is at peak system load.

Is the organization better off curtailing for that long and realizing the savings in subsequent peak charges? Or would the organization be better off participating in demand response, which, if not called for an emergency event, only involves just one test hour during the summer?   

It’s best for a given organization to consult a licensed curtailment service provider that has the ability to evaluate all of an organization’s energy assets and explain how they may best be leveraged in PJM’s existing markets to optimize savings and earnings through demand-side energy management.


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

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