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.
In our last ERCOT blog post, we laid out the record high demand/historically low supply scenario facing ERCOT and its customers this summer. As we reported, ERCOT acknowledges that this situation could result in emergency energy alerts. This will more than likely result in high electricity prices, perhaps record high prices. If you participate in ERCOT’s Load Resource (LR) demand response program, those high prices will mean generous revenue paid to you for participating in LR.
In the rush to enroll in LR and capitalize on some Texas-sized payouts before the summer enrollment deadline, though, a lot of commercial and industrial customers have encountered an unexpected ERCOT roadblock: UFR. And they want to know: What’s a UFR? What’s it got to do with LR DR? Why do I need it? And how do I get it?
To answer these questions and get everyone on the path to significant summer revenue, we have to start with dirty power.
Dirty power is a term used to describe electricity that is affected by abnormalities such as power surges, excessive line noise, and fluctuating frequency. It usually describes power intended for delivery through the electrical grid, and that’s how we’ll use it here. It can have several causes, but the end result is almost always the same: damage to your equipment and infrastructure that can cripple your daily operations.
You probably don’t think of electrical power as “dirty.” It’s hard to imagine, perhaps because you can’t see, smell or touch it. You can see, touch or smell dirty water and dirty air. Same with work clothes, office windows, and motor oil.
But electric power can in fact be “clean” or “dirty.” Unlike the examples above, though, dirty power stays dirty. You can’t clean it, at least not easily. The abnormalities that make it “dirty” are usually generated at the source and can flow to the farthest reaches of the grid almost instantly.
Wind is a major source of dirty power. Ironically, it’s also the current centerpiece of Texas’s nation-leading embrace of “clean” renewable energy. The Lone Star State’s drive to incorporate more renewable energy sources to power the grid has established Texas as the largest producer of wind power in the U.S. ERCOT says wind accounted for 17.4 percent of electricity generated in its service area (roughly 90 percent of Texas) in 2017.
But this intermittent source of power generation is also a major source of “harmonics” — a distortion of the underlying sinusoid of a signal, referred to as over or under frequency events. That’s dirty power. West Texas, where there are a lot of wind generators, is dramatically affected by frequency changes. As the wind increases or decreases, the generation created by wind turbines flows onto and off the grid, causing frequency changes as the load drops and rises. At the least, these frequencies can cause overheating and premature equipment failure.
That brings us to UFR. UFR stands for Under Frequency Relay. According to IEEE, UFRs are used to automatically shed a certain amount of load whenever the system frequency falls below an acceptable level for grid stability. Think of it as an industrial-strength circuit breaker that protects the grid — and your business — from shorting out.
So, why does ERCOT require that LR participants have UFRs installed? Because UFRs help them fulfill their mission to maintain the security and reliability of the ERCOT system. That includes helping the grid stabilize autonomously by stopping the spread of Under Frequency.
As the number of wind turbines dotting the windswept Texas plains has increased, so has the possibility of frequent under frequency conditions. So has the need to stop the spread of UFR throughout the grid. (The oil and gas communities across West Texas were among the first to adopt UFRs in the fields, largely to protect their machinery.)
To do that, they need you. Customers that can meet certain performance requirements can be qualified to provide operating reserves as a Load Resource and be eligible for a capacity payment. In short, LR DR. And that requires that an Under Frequency Relay be installed that opens the load feeder breaker on automatic detection of an under frequency condition.
As we noted above, dirty power can spread easily and rapidly across the state and affect every organization attached to the grid, especially commercial and industrial concerns. And we also noted that to be considered a Load Resource and receive capacity payments, you have to be available as needed. A great way to knock out an available Load Resource is dirty power in the form of an under-frequency condition. UFRs assure that your availability will not be affected by this particularly spreadable form of dirty power.
If you want to enroll in LR and don’t have a UFR, CPower can help. We work with world-class third-party resource vendors and partners who can design and install UFRs to the exact specifications of the CPower curtailment plan developed for your facility. By working with the best, we assure you of the best opportunity to save and earn.
You don’t need a UFR to go about your daily business. But you do need it to receive the financial benefits of being a Load Resource available to provide invaluable operating reserves as needed. Considering that the growth of renewables, especially wind, shows no signs of abating in Texas, and with it the threat of under frequency conditions, having a UFR might just be a good idea, period.
The 2019 State of Demand-Side Energy Management in North America is 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.
UPDATE March 5: ERCOT announced today that, due to expected record high demand and “historically low” 7.4% expected reserve margin, they have “identified a potential need to call an energy [emergency] alert at various times this summer.” (Emphasis ours.) Alerts allow ERCOT to take advantage of resources available only during scarcity conditions—particularly demand response. ERCOT will release its final summer report in May.
Two significant factors projected for ERCOT — the Electric Reliability Council of Texas—stand to have a noticeable impact on its energy market: Reduced supply and record peak demand. The resulting clash between these two market drivers point to the very real possibility of unexpectedly high prices for organizations participating in ERCOT’s Load Resources (LR) demand response program. Let’s take a look at what’s driving these two important factors, and how this could translate into an opportunity to generate revenue through demand response.
Reserves have dropped dramatically. Since mid-2017, ERCOT has approved the retiring of four coal-fired generation plants responsible for generating more than 4,500 MW in capacity. It’s not just coal generation, though. Since the May 2018 Capacity, Demand, and Reserves (CDR) report, three planned gas-fired projects totaling 1,763 MW and five wind projects totaling 1,069 MW have been canceled. Another 2,485 MW of gas, wind and solar projects have been delayed.
In its December 2018 CDR report, ERCOT projected total available generation capacity for Summer 2019 at 78,555 MWs—an estimate, as it turns out, that’s too low. ERCOT recently learned that it is losing another 470 MWs from the Gibbons Creek coal plant going offline this summer. That drops reserve capacity to 78,085 MWs—a low, low 7.4% reserve margin, just over half of the long-standing target margin of 13.75% of peak electricity demand.
And demand will peak. Last year, ERCOT set an all-time peak demand record of 73,473 MWs on July 19 between 4 and 5 p.m. This year, ERCOT predicts more “record-breaking peak demand usage” for the summer: 74,853 MWs, 1300 MWs higher than last year’s all-time peak.
That leaves a gap of—hold on—just 3,232 MWs. Low supply. High demand. Tight, tight margins. All that adds up to the potential for record high prices in ERCOT’s Load Resources (LR) ancillary services demand response program that ERCOT deploys to maintain sufficient operating reserves.
Already, LR prices have increased since the retiring of 4,200 MWs of generation in 2018. (see chart.) Additionally, projected wholesale energy prices in ERCOT for Summer 2019 are some of the highest we have seen. It’s not a stretch to anticipate high, if not record high, LR prices this summer.
High prices in Load Resources mean generous revenue paid to you for your participation in the program which pays businesses for being available to curtail energy on short notice when the grid is stressed. LR has the potential to pay organizations two to three times more than other ERCOT demand response programs.
CPower can help you get the most out of the Load Resources program by working closely with your organization to develop a customized curtailment strategy, including automation, that suits your business objectives and operational considerations. Start the conversation today. Learn how to maximize your curtailment revenue with CPower and ERCOT’s LR program.
The clock has started ticking down on backup generators in California’s demand response programs. On January 1, 2019, the California Public Utilities Commission’s Demand Response Prohibited Resources decision officially takes effect. The decision (officially Decision 16-09-056) mandates that fossil-fueled resources can no longer be used to provide demand response.
The decision doesn’t remove fossil fuel generators from use for backup or for facility power generation, just from demand response (DR). It’s clear, though, that they face near-certain elimination from the California power landscape in the near future. The historic green energy bill signed by Gov. Jerry Brown on September 10th, 2018, specifically requires that 50 percent of California’s electricity be powered by renewable resources by 2026—seven short years away.
Needless to say, this has some profound implications for the future of distributed energy resources (DERs) and DR in the nation’s most populous state (and the world’s fifth largest economy). California’s “bold path” toward 100 percent zero-carbon electricity by 2045 will take it through uncharted territory potentially full of threats to the reliability of its far-flung electrical grid and the costs of the electricity it provides.
Demand response in California, as elsewhere in the country, has been a valuable tool in managing demand-side energy use, protecting the grid, and funding progressive sustainability initiatives. Generators have been a valuable part of DR, providing additional opportunities to save and earn as part of their commitment to a balanced California grid. But California has long been strict on the use of non-emergency generation for demand response, and the green energy bill tightens restrictions to an outright ban.
With fossil-fuel generators permanently pulled from DR participation in California, then, the question facing participants is, “Now what?” There are no easy answers—in a constantly evolving energy universe like California’s, there never are. That said, CPower recommends a couple of steps you can take to ease your transition into a post-fossil fuel world and continue to save and earn.
No Generators? No Problem.
The 2015 court ruling that vacated the EPA’s rule—referred to in the industry as “the Vacatur”—took effect in 2016 and upended DR participation. Hundreds of fossil-fuel backup generators were withdrawn from DR programs in most of the nation’s wholesale energy markets
One water agency, though, found they could still successfully participate in DR without their generators. Virginia’s Lake Gaston Water Supply Pipeline supplies water to Virginia Beach, the state’s most populous city. The Vacatur forced them to withdraw their diesel-powered generators from their DR program. Without the generator to sustain pumping during curtailment as part of DR, they faced the prospect of not being able to curtail the required power during an event, which meant pulling out of DR completely.
Working with CPower, Lake Gaston’s curtailment service provider since 2010, managers were able to research new methods of DR participation without generators. These measures included a full pump shutdown, something they weren’t sure they could do successfully. After a thorough analysis and review of their operations with CPower, it turned out that they could. Read the full story here.
Back to Basics
Before you mourn kilowatts lost, take a moment and consider if there are kilowatts to be found to replace them. Start by asking yourself, “What’s changed since I received my first demand response check?” The answer might be, “Everything,” or something close to it.
How have your day-to-day operations changed in response to changing market conditions? What upgrades have you made to your lighting, HVAC, IT, security, and communications? Is your physical space smaller or bigger? Have you added locations? What’s the state of your building envelope? Is it sufficiently insulated? Has on-site staffing grown or declined?
These are questions to be answered when you have a knowledgeable energy engineer, like those at CPower, conduct a thorough assessment of your facility. Your new “deep dive” assessment forms the foundation for creating a new curtailment action plan, one that matches your available kilowatts to available demand response and demand-side energy management programs. Chances are you’ll find new kilowatts to replace those lost from removed generators, and possibly more.
Dollars for DERs
Now is the perfect time to think beyond the generator and embrace other dispatchable distributed energy resources, or DERs, for your backup power. Behind-the-meter technology like storage batteries—charged by renewable but intermittent resources like sun and wind as well as grid energy—can be enrolled by CPower in California’s demand response programs (Capacity Bidding Program, Base Interruptible Program, and Demand Response Auction Mechanism aka DRAM) as available generation to help when the grid is stressed. You can combine your DER asset with demand response programs to offset kWs lost from generators.
For example: California State University, Dominguez Hills is one of the most sustainability-focused campuses in the state system. In 2017, CSUDH joined with CPower and Stem, provider of the school’s 1 MW intelligent storage system, to create a combined curtailment and storage program. By stacking these technologies, CSUDH significantly reduced their environmental footprint, provided approximately 400 kW of grid relief, and generated revenue that flows back to the school to fund further sustainability initiatives. For their efforts, CSU was also recognized with the 2018 Smart Energy Decisions Innovation Award for Customer Project/Onsite Renewable Energy.
As California moves toward 100% zero-carbon energy, it’s safe to say that fossil-fuel generation, on both the micro and macro level, will continue to be phased out. Demand response, however, will continue to have an important role in California’s energy re-imagining. Demand response continues to fulfill its primary role, protecting the grid of the world’s fifth largest economy. Look for thought leaders and decision makers to find new and better ways to integrate renewables and dispatchable renewable energy resources into statewide demand-side energy management programs. And look for CPower to continue to advocate on behalf of our customers to ensure their ability to save and earn while protecting the grid.