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Managing Rising Costs Amidst the Alphabet Soup of NY Energy Initiatives

By Mike Hourihan | January 30, 2017

If you’re a mid- to large-sized energy user in New York, you’ve likely come across a veritable alphabet soup of acronyms: REV, CES, DR, DER…the list goes on. Many of you who run commercial and industrial (C&I) businesses know that you can actively leverage Demand Response (DR) programs and earn revenue by curtailing load when called upon to do so during emergencies to support grid reliability. Granted, some years have been more rewarding than others since capacity prices ebb and flow in New York just like in other energy markets. Of course, capacity prices have risen substantially since 2012, resulting in increased earnings from DR participation in New York. So what can DR participants across New York expect in 2017 and beyond?

First, a bit of context on REV and CES:

In 2012, Hurricane Sandy hit the East Coast, causing devastation and leaving millions without power.  Shortly thereafter, working with the New York governor’s office, New York Power Authority and other state agencies, the Public Service Commission (PSC) launched the landmark Reforming the Energy Vision regulatory proceeding. Now commonly referred to as REV, its goal is to make the power system cleaner, resilient and more affordable. Regulators aim to transform traditional utilities into platform providers — entities that facilitate the deployment of distributed energy resources (DERs) and use them instead of traditional infrastructure.  And Demand Response is poised to continue to play a vital role as this initiative evolves.

In simplest terms, the Clean Energy Standard (CES) mandates New York to acquire 50% of its energy from clean resources by 2030. As part of this, it seeks to further that goal by providing zero-emission credits (ZEC) to support upstate nuclear plants that were in danger of closing. In late 2016, the PSC fended off numerous challenges to its adoption of the CES and its subsidy for nuclear power generators. Keep an eye on this space, however, as the PSC’s order doesn’t mean this is finalized (as of this writing in Feb 2017, two court challenges remain pending). Generators and some environmental advocates said the ZEC program — which critics say will cost over $7 billion over its 12-year lifespan — goes beyond the authority granted to the PSC by state law.

Impact on your bottom line:

In the near term at least, REV and CES, while noble causes, are going to lead to increased fixed costs (~$4/MWh) on mid- to large-sized energy consumers.  This scenario, however, also presents additional opportunities and specific actions you can take today to offset these costs:

  • Increased DR participation especially in new distribution utility programs, and
  • Capacity tag management.

New DR Programs: Both the NYISO and New York Electric Utilities offer demand response programs that pay businesses like yours for using less energy when the grid is stressed. Many commercial and industrial businesses in New York aren’t aware of the new summer-only local utility programs available to them via an authorized DR services provider. These programs offer another revenue stream in addition to the NYISO DR program that they may have been enrolled in for years. In 2016 for example, the New York Public Service Commission mandated that local utilities provide a Commercial System Relief Program (CSRP) throughout their entire service territory as part of a statewide effort to develop a new regulatory framework which includes incentives to leverage the deployment of distributed energy resources such as demand response.

Capacity Tag Management: Additionally, there are demand management services that can help significantly lower your capacity charge which make up 20-40% of the total supply portion on your monthly utility bill. The capacity charge is based on your individual capacity tag which, in New York, is determined by your facility’s usage when the NYISO sets its single annual peak hourly demand across the whole system. CPower sends an advanced day ahead demand management notification to reduce your usage when it is likely the NYISO will hit its hourly peak demand, thus reducing your capacity tag and capacity charges for the following year.

In the end, it’s all about implementing smarter techniques to manage your overall energy spend. The NYREV was launched 3+ years ago but it’s more relevant now than ever to survive as a large C&I energy user, as it will certainly change how energy is transacted in the future. At CPower, our job is to stay abreast of these developments and keep you informed about their potential impact. To get started, check out the various programs available in NY and informational videos to learn more on how you can offset rising energy costs in 2017 and beyond.

Split Decisions: All Demand Response Splits are NOT Created Equal

By Trevin Eckersley | November 02, 2016

Like energy, demand response (DR) is too often positioned as a commodity by businesses offering curtailment services. As is the case with most commodities, the best price usually wins. However, that mentality can end up costing you and your company valuable revenue in the long run when it comes to selecting a curtailment service provider (CSP) based solely on the DR split that provider offers.

Consider two DR proposals from the customer’s perspective. One promises a 90/10 split (90% of the revenues earned go to the customer, 10% to the CSP), while the other is an 80/20 split. Clearly the former is the better choice for the customer, right?

Not so fast. When faced with a “split decision” concerning DR, you should always ask a few key questions:

Who’s handling my demand response?

Would you rather receive 90% of the earnings from adequate DR participation or 80% of the earnings from optimized demand response?

It’s a tough question that requires more information before you can make the best decision, but now we’ve at least agreed that demand response is not a commodity… it’s a service.

Service Defined

Some CSPs are much better than others at providing the service of helping businesses curtail more energy and therefore help them earn more revenue from demand response.

How can my company better judge which CSP is going to provide the best DR service?

Imagine you’re an athlete with recurring pain in your foot. Would you prefer to speak to a general practitioner who may be knowledgeable about the entire human anatomy? Or would you rather consult a podiatrist, whose entire practice specializes on the study and effective treatment of the human feet?

You get the point here. Some CSPs are like general practitioners of energy management. They are knowledgeable about a broad array of energy products, and only offer demand response as part of their repertoire of services. They often have hidden fees and/or outsource many of the intricate pieces needed for successful DR implementation, including engineering, dispatch, billing, payment, settlements, etc. Moreover, many customers may not realize that in some markets just one single day of missed or reduced participation could eat up ALL of their “perceived” savings.

Then there are the specialists—CSPs who focus solely on demand response and who seek to do little else than optimize DR participation in an effort to yield maximum revenue for their customers. These are the service providers who understand the nuances of effective DR participation to optimize energy earnings and savings.

Can a better split result in less revenue earned from demand response?

Let’s go back to the decision of choosing the best split. Is a 90/10 split on demand response unequivocally better than an 80/20 split?

The answer depends on how much revenue a given organization earns from demand response.

If the CSP offering a 90/10 split and can help a business curtail enough energy through demand response to warrant $90,000 annually, that may be considered pretty good.

On the other hand, if a CSP who specializes in demand response and offers an 80/20 split can help the same business optimize its curtailment efforts and earn $125,000 through demand response, that’s typically seen as better since you’ve earned more money as a result of your DR participation.

Of course, that a given CSP helps your business earn more revenue isn’t the only reason to consider selecting that company to handle your demand response participation. Quality service, a transparent process for accurate, prompt and timely payments, and having a dedicated team standing by to answer any DR-related questions you may have should also be considered.

When it comes to decisions about demand response “services” and choosing the best CSP for your business, there is more to the bottom line than just the split. A LOT more.

Please feel free to contact Trevin or the CPower team if you have any questions. Our team is happy to help you understand the nuances of participating in these DR programs and assist in optimizing your overall energy savings and earnings year round.

Hot Summer Ends Without Emergency Demand Response Events in PJM

By Dann Price | October 07, 2016

The 2016 PJM summer compliance season which runs from June through September has come to an end without a PJM-initiated emergency demand response (DR) event.  The first six months of the year were already one of the warmest on record. So, for many of us sweating it out across the northeast, it was no surprise that this summer produced several heat waves that pushed system peaks to their highest levels in recent years.  PJM’s top 5 system peaks (see table), reflect the summer’s weather and should be the Five Coincidental Peaks (5CP) that drive customers’ capacity charges through their Peak Load Contribution (PLC).  It is important to note that any load reductions during these hours may reduce your capacity charges for next summer.


When it came to actual demand response events, however, a different picture unfolded compared to prior years. For instance, the 2013 summer saw system peaks at similar levels and was one of the most active summers for demand response customers ever.  So you may ask: Why were no Emergency DR events called this summer, despite the heat and high system peaks? A few reasons come to mind:

  1. Some of it may be attributed to PJM’s new reliability product, Capacity Performance (CP), which debuted this delivery year and imposes greater availability requirements on generation;
  2. Some of it may be attributed to increased transmission efficiency;
  3. Also, flat or declining system peaks are starting to reflect the impact of energy efficiency regulations (the last system peak demand record was set in 2007); and finally
  4. Pure Luck? After all, the timing of several heat waves passing through the PJM territory coincided during weekends.

Whatever the primary reason(s), PJM Emergency DR customers should take pride in their commitment to be on standby to reduce load when called upon. Your ability to curtail electricity consumption when needed by the grid is a tremendous asset to maintaining system reliability and preventing potential blackouts/brownouts.

This doesn’t mean that PJM may not have a reliability issue beyond the summer as the program year does run through May 2017. Also, while the summer period yields the greatest risk of an emergency event, demand response customers that have committed to curtailments all year should continue to be prepared to perform and reduce load if/when needed to support grid reliability.

Moreover, with the transition to the new CP product, demand response is morphing into a year-round program. Customers can start participating in CP now to get themselves prepared for the coming changes and earn additional capacity revenue in the process. Many forward-thinking facility managers are already thinking about how they may be able to participate beyond the summer and are reviewing effective winter curtailment strategies.

CPower would like to take this time to thank all demand response customers for their commitment to PJM reliability this summer.  CPower customers can always review their load drop test and event performance in the CPower App and should be expecting summer performance reports and payments starting early November.

Last but not least, we always encourage all participants to stay tuned for earnings opportunities in other DR programs available. Many participants augment their demand response earnings from the capacity program via active participation in PJM’s voluntary programs such as (price based) economic demand response and (faster response) ancillary services such as synchronized reserves.

Please feel free to contact Dann or the CPower team if you have any questions. Our engineering team is happy to help you understand the nuances of participating in these programs and assist in optimizing your overall energy savings and earnings year round.

NYISO is Ready for Summer Demand. DR Customers Should be Ready, too.

By Craig Markham | August 17, 2016

What can demand response participants expect in New York this summer? Let’s take a look at a few factors.

NYISO reports adequate summer supply, though concerns loom in Western New York…
On May 19, 2016, NYISO issued its ritual summer press release stating, “Electric supplies in New York are expected to be adequate to meet forecasted demand this summer.” However, at the time there was considerable stakeholder trepidation over potential transmission constraints in Western New York arising from the recent retirements of the Dunkirk Steam and Huntley Generation stations. There was an anecdotal sense that energy and reserves pricing in the early spring was already showing more volatility than normal.

NYISO has undertaken a number of initiatives over the past 18 months to bolster infrastructure in the region to improve transmission flows and reactive capacity. They have also implemented changes in their intraday forecasting procedures for the region to better manage congestion, in an attempt to minimize real-time pricing volatility.

How have these factors affected in the markets thus far…
The concern didn’t appear to much spill-over into the capacity market. The Rest of State Strip auction cleared at $3.62 for Summer 2016, up only 12 cents from the summer of 2015, despite the unit retirements. Spot auction prices jumped up to $5.27 in May, but have since retreated back near the Strip price at $3.64 for August. On balance, not a significant deviation from the prior year. And like the previous year, there have so far been no dispatches for Special Case Resource (SCR) customers.

In the 10-minute synchronous reserves market, the 12-month rolling average 5-minute real-time price in the West zone (Zone A) is actually down by almost 20% over the past year. Over the same period, the standard deviation in prices has increased by about 6%, so there has been a slight uptick in volatility. Moreover, similar trends can be observed in neighboring zones (B and C) that do not have major transmission constraints.

In the real-time energy market, the 12-month rolling average congestion component of the 5-minute real-time price in Zone A is up by more than 32% over the past year. Volatility has also increased as the standard deviation of congestion charges is up by more than 21% over that same time period. Congestion charges are also more than 20 times higher over the past year than in neighboring Zone C.

So it appears that NYISO’s system measures have so far confined the impact of mothballing Dunkirk and Huntley to higher pricing in the energy market. And while there appears to be no significant impact on the capacity and reserves market, the increased congestion and volatility reflected in energy pricing raises the likelihood of a capacity dispatch when the overall New York system becomes more constrained under hot weather conditions. Demand response customers in these western regions should be prepared for potentially more curtailment calls from NYISO than they’ve seen in previous summers.

To learn more about how to be better prepared for potential grid instability this summer in New York, contact Craig or any member of CPower’s New York Team.

What ERCOT’s Seasonal Demand Predictions Mean for Demand Response in Texas this Summer

By Peter Dotson-Westphalen | July 07, 2016

ERCOT is ready to meet summer demand.
On May 3, 2016, ERCOT released seasonal and 10-year outlooks that anticipate adequate generation capacity for upcoming electricity demands in Texas. According to the ERCOT’s Director of System Planning, Warren Lasher, the ISO expects to have ample generation to serve its customer’s needs this summer. “However,” according to Mr. Lasher, “hotter-than-normal weather combined with low-wind conditions or high generation outage rates could cause operating reserves to drop below target levels, making it necessary to take additional actions to maintain grid reliability.”

ERCOT is not expected to see any significant pricing fluctuations this summer.
Response Reserve Service (RRS) pricing, determined by the Day-Ahead Market, has the potential for price spikes. However, such spikes seem unlikely given the low natural gas prices and high wind generation capacity working to suppress current clearing prices set by power generators.

An event like the one mentioned in the ERCOT’s press release could lead to a price spike in the Day-Ahead or Real-Time Markets. Such an event could also trigger emergency operational procedures, potentially resulting in the dispatch of Load Resources or Emergency Reserve Service.  However, unless we realize more formidable weather conditions, we can expect prices to remain where they are this summer.

Localized dispatch of Load Resources (LR) is a possibility in certain ERCOT regions.
Last fall ERCOT called a LR event in the Rio Grande Valley due to congestion in the region. While there is no cause to anticipate a similar event being called this summer, the region could be one that experiences the kind of “hotter than normal” weather the ISO has warned of and should be on alert for dispatch.

ERCOT has made a change to how they procure Ancillary Services that will affect the summer season.
ERCOT has made a change to how they procure the RRS Ancillary Service. They have removed the Reserve Discount Factor, which served to reduce a generator’s available capacity during periods of likely higher temperatures across the grid, from the calculation. Instead, ERCOT will now procure an additional 200 MW of RRS during Hours Ending 15-18 during July and August of 2016 only.

To find out more about what you can do to prepare for the summer season in ERCOT, contact Peter or anyone on CPower’s ERCOT team.

How Weather and Capacity Performance will Affect Demand Response in PJM this Summer

By Dann Price | June 16, 2016

El Nino, La Nina, and Capacity Performance could have an impact on demand response in PJM this summer. Let’s take a look at a few reasons why.

PJM is prepared to meet summer demand. Weather conditions are forecast to be mild, but don’t rule out emergency events.
In a May press release, PJM stated the RTO is prepared to meet the expected power demand of its more than 61 million customers this summer. The early patterns of the El Nino and La Nina cycles indicate we are expected to see milder temperatures early in the summer and hotter conditions in the late summer and early fall.

That’s not to say demand response participants shouldn’t expect an emergency event this season. PJM can still call events for smaller localized disturbances or if generation units in the region trip offline. That said, heat related calls should be minimal.

The addition of Capacity Performance (CP) on the system should help hold off PJM event calls as the Capacity Performance program requires resources to be available more often.

As usual, CPower tends to schedule the PJM mandatory test event early in the summer to ensure customers will have time to be retested in the event they under-perform. CPower customers should be on the lookout for our test event messaging.

Capacity charges on your supply bill will be higher than expected due to the Capacity Performance and the Transitional Auction.
The Base Residual Auction (BRA) set the capacity charge for customers. However, when PJM introduced Capacity Performance (CP) and adjusted their peak load by procuring 60% CP, they purchased the CP at a higher cost than the annual capacity. This will raise the total cost of capacity being allocated back to Load Serving Entities, who will in turn pass those costs along to the end user.

As always, demand response is a great way to offset increasing costs. However, the addition of Capacity Performance should result in less need for demand response resources to ensure grid reliability.

Results from the 2019/20 Base Residual Auction indicate a changing landscape and market dynamic for demand response resources in PJM.
This year’s BRA was the last that will include a seasonal or summer capacity product. Next year’s BRA for the 2020/21 delivery year will only contain the Capacity Performance product. For the 2019/20 BRA, PJM had adjusted their load forecast down to compensate for a few changes, most notably existing Energy Efficiency projects as their impact reduces the need for additional capacity.

This summer is the first to include capacity that will follow PJM’s Capacity Performance standards. Capacity Performance resources must produce electricity when called on regardless of weather conditions or extreme system conditions. Committed resources that do not perform when called upon will face significant non-performances charges. These resources were committed in a transitional capacity auction in August 2015.

To learn more about PJM’s changing market or about how to be better prepared for potential grid instability this summer, contact Dann or any member of the CPower’s PJM Team.

What the Worst Gas Leak in US History Means for Demand Response in California this Summer

By Jennifer Chamberlin | June 14, 2016

Demand response participants will play an essential role in keeping Southern California’s energy grid stable this summer. Here are a few reasons why and a few insights on how DR customers can position themselves for a successful season.

The leak at Aliso Canyon has consequences for energy supply in California.
In October 2015, Aliso Canyon— the largest natural gas storage facility in California—suffered a leak in the LA Basin/Porter Ranch area, resulting in the emission of more than 97,000 metric tons of methane. To put the tonnage in perspective, the leak produced enough methane gas each day to fill a balloon the size of the Rose Bowl. The leak was plugged after 112 days.

The fallout has proven costly for the natural gas infrastructure in Southern California. According to the “Aliso Canyon Risk Assessment Technical Report,” the leak reduced Aliso Canyon’s gas stores to less than 20% of its capacity.

Low capacity means high risk for blackouts this summer.
The drop in capacity could cause trouble for the 17 natural gas generators served by the Aliso Canyon facility if (and when) electric demand is high this summer. The Assessment Report also  warns that millions of California customers may suffer an interruption in electrical service during as many as 14 days this summer when demand is expected to be at its highest.

The grid will be at its most fragile in the evenings when the sun sets, causing a drop in available solar resources.  The drop in solar coincides with a spike in demand as people come home from work and flip on their air conditioning.

The “Duck” Curve: California experiences a daily spike in demand in the early evening when renewable energy sources like solar tend to drop. The trend has become increasingly extreme since 2012.

Demand Response will help grid reliability.
The joint agencies that produced Aliso Canyon Assessment Report have also drafted an Aliso Canyon Action Plan that calls for, among other mitigation strategies, demand response to help keep the grid stable in the LA Basin this summer.

California’s  Base Interruptible Programs (BIP), in which participants provide load reduction on a day-of basis in Southern California Edison’s (SCE) and Pacific Gas and Electric’s (PG&E) service territory, allows for fast dispatching of emergency resources and is therefore expected to be heavily utilized to alleviate grid stress in Southern California this summer

The LA Basin is expected to bear the brunt of California’s diminished capacity as a result of the leak at Aliso Canyon.

How energy prices may trigger key curtailment programs:
Summer electricity prices may climb high enough to trigger SCE’s Aggregator Managed Portfolio (AMP) program, as well as statewide Demand Response Auction Mechanism (DRAM) programs, which aim to offset grid stress and avoid potential blackouts by reducing load via demand response.
Due to the high amounts of solar and other renewable generation available in California during the call hours of these programs, overall energy prices are not as tightly correlated with natural gas as they can be in other states.

The gas shortage caused by the leak at Aliso Canyon will drive heat rate levels in the LA Basin. This will cause natural gas heat rate triggered programs like CAISO’s Capacity Bidding Program (CBP) in PG&E to have a potentially higher instance of calls this summer.

Preparation is the key to successful demand response.
This summer, more so than in previous seasons, demand response will be a crucial component of grid reliability! When the grid sends out its distress notice, time will be of the essence to avoid blackouts. Make sure your curtailment plans are in place and your curtailment personnel are at the ready.

CPower can help answer any questions you may have to help you prepare for the summer season. Click HERE to contact our California team.

The City of Danville Finds Success with Demand Response and CPower

By CPower | March 28, 2016

AMP Member passes ordinance, increases revenues through energy reduction

Hardworking businesses form the backbone of the City of Danville, Virginia. When it comes to overseeing the energy needed to run the city’s economic engine, Danville Utilities—the City of Danville’s electrical department—understands the need to maintain balance between consumption and conservation.

“As a municipal utility, we are always encouraging our customers to find ways to save energy,” says Meagan Baker, Danville Utilities’ Key Accounts Manager. The City of Danville — an AMP member municipality — perpetually seeks ways that not only allow their customers to conserve energy, but also allow the utility to save on congestion and transmission charges during the most critical peak times of the year.

Enter demand response and, what the City of Danville calls, “a win-win situation for the utility and the customer.”

In early 2014, the City of Danville adopted a resolution authoring their participation in the PJM demand response program for retail customers. The resolution allowed Danville’s city manager to execute an agreement with American Municipal Power approving the city’s participation in PJM’s demand response programs, which pay businesses for reducing their energy use during the few times each year when the PJM grid is stressed.

The agreement also named CPower as the City of Danville’s exclusive PJM curtailment service provider in charge of implementing and facilitating the city’s demand response. Danville Utilities believes their customers couldn’t be in more capable hands.

“CPower has been a great source for implementing our demand response program. Bill Oosterom, our account manager, has been our go-to person from start to finish. From educating customers about the program, getting them enrolled and assisting with any questions and/or concerns they have along the way, the process has been very transparent and straightforward. This streamlined approach makes it easier on our customers as well.” – Meagan Baker Key Accounts Manager, City of Danville

The City of Danville Finds Success with Demand Response and CPower

CPower’s hands-on style of energy management includes the kind of customer-focused touch the business owners of Danville appreciate. CPower’s Bill Oosterom believes that being personally involved in his customers’ demand response participation is a key reason the City of Danville has enjoyed energy management success.

“No two businesses are alike,” says Mr. Oosterom, who has more than 33 years of experience as an energy consultant. “Demand response shouldn’t be a set-it-and-forget-it process. At CPower, we work closely with all our customers to fine tune their demand response participation over time and ensure they get the maximized results and revenue they deserve.”

So far, the results from the City of Danville’s demand response participation have proven to be substantial. Participating customers have earned significant revenue through demand response (more than $97,000 in aggregate for the 2015-2016 program years), with many businesses choosing to put their earnings toward energy efficient upgrades or other capital improvement projects.

Even the City of Danville, itself, has participated in demand response with great success. Facing a need to offset operational costs, the City of Danville enrolled its municipal owned water and wastewater treatment plants in the program and have now earned valuable revenue (more than $30,000 for the 2015/2016 program) to help budgets of future projects. Civic leaders feel the City of Danville’s involvement in demand response provides a lead-by-example model of energy management. “We are always asking our customers to conserve,” says Meagan Baker, “so we must practice what we preach.”

For the City of Danville, the future looks bright as the number of businesses in their municipality participating in demand response is on the rise. With CPower and demand response on their side, the City of Danville is poised to do their part to keep the grid in balance, the environment in good health, and their hardworking customers in expert hands when it comes to energy management.

“The program has been very beneficial in educating our customer base on the importance of energy efficiency and demand response. As our customers continue to succeed, I believe the word will spread, positively influencing other customers to also become involved. We are excited to grow the program.” — Meagan Baker

AMP urges you to pass your local demand response ordinance as quickly as possible, to ensure that there is ample time for program participants to be registered for the 2017-2018 program year.