Our Blog On-Demand

Content


Knowledge Hub

FERC Order Removes Restrictions for Utility Demand Response Resources in New York Zones G-J

March 18, 2021

Good news on the regulatory front for new demand response resources from New York’s zones G-J entering NYISO’s Installed Capacity Market.

On February 18, 2021, the Federal Energy Regulatory Commission (FERC) issued an Order that overturned a portion of its previously issued Oct. 7, 2020 Order in the paper hearing on whether utility demand response programs Commercial System Relief Program (CSRP) and Distribution Load Relief Program (DLRP) are intended to provide benefits solely to the distribution system (i.e. not for providing similar services to wholesale capacity) and whether the revenues from such programs should be included in new Special Case Resources (SCR) entering the market in New York’s ‘Mitigated Capacity Zones’ G-J Offer Floor calculations as part of Buyer-Side Mitigation (BSM).

NYISO Zones G through J

FERC’s Feb. 18 Order excludes CSRP revenues (in addition to DLRP revenues as the Oct. 7 Order did), making it much more feasible for most new SCRs to pass the Offer Floor test and not have to sell into New York’s installed capacity (ICAP) market at a price point that is unlikely to clear.

Customers located in Mitigated Capacity Zones who are new to the NYISO SCR program are now significantly less likely to 1) be subject to Buyer-Side Mitigation (BSM) and 2) be required to offer to sell capacity at or above an offer floor price that may not clear in the market.

Rather than run the risk of being found subject to buyer-side mitigation and have an offer floor applied (that carries with the Resource until it clears in at least 12, not necessarily consecutive, monthly Spot Auctions), DR participants will no longer need to choose between retail and wholesale markets to provide DR.

Resources capable of providing different types of DR services will be able to realize the full value, benefiting both the bulk power and distribution system operations.

The order helps to unlock the full value stack of wholesale and retail demand response values to participating customers. Subsequently, new demand response customers no longer need to choose between retail and wholesale markets in which to provide demand response resources.

What is Buyer-Side Mitigation?

Buyer-Side Mitigation (BSM) helps maintain the New York energy market’s integrity by preventing power providers from exerting market power by offering into the capacity market at an artificially low price.

BSM helps ensure both energy providers and generators are not able to exercise unfair buyer-side market power—a form of monopoly control over a market.

For example, energy providers that receive “out-of-market” payments such as state subsidies could have an unfair advantage over other power providers who do not receive out-of-market payments when it comes to offering in New York’s capacity market since the subsidized resources could offer into the market at a price that is lower than that of unsubsidized resources. 

Allowing subsidized resources to offer into the capacity market at an artificially low price would distort the actual cost and the resulting market price of capacity when power providers compete fairly in the free market. 

What is the Offer Floor Test?

Without getting overly complicated with details, the Offer Floor test is used to determine if a given resource is either subject to or exempt from Buyer-Side Mitigation.

NYISO defines the Offer Floor Test’s calculation for new SCRs as follows:

The Offer Floor for a Special Case Resource shall be equal to the minimum monthly payment for providing Installed Capacity payable by its Responsible Interface Party, plus the monthly value of any payments or other benefits the Special Case Resource receives from a third party for providing Installed Capacity, or that is received by the Responsible Interface Party (RIP) for the provision of Installed Capacity by the Special Case Resource, except that it shall exclude the monthly value of any payments or other benefits the Special Case Resource receives from a retail-level demand response program designed to address distribution-level reliability needs that the Commission has, on a program-specific basis, determined should be excluded.

A Brief History of Buyer-Side Mitigation and Special Case Resource in New York

The preceding article’s timeline begins in February 2021 with FERC overturning its October 2020 order. Let’s review how the issue has evolved over the previous thirteen years. 

Much of the following has been paraphrased from Section II of Docket No. EL16-92-001-NY Public Service Commission v. NY Independent System Operator

Special Case Resources have been subject to NYISO’s Buyer-Side Mitigation since September 2008. In May 2010, FERC approved an Order that excluded certain payments that an SCR may receive from state-regulated, distribution-level demand response programs. 

In March 2015, FERC clarified that it did NOT intend to grant an “exemption for all state programs that subsidize demand response” and further explained that a state “may seek an exemption from the Commission [FERC] pursuant to section 206 of the Federal Power Act if it believes that the inclusion in the SCR Offer Floor of rebates and other benefits under a state program interferes with a legitimate state objective.”

On June 24, 2016, the NYSPSC, the New York Power Authority, the Long Island Power Authority, NYSERDA, the City of New York, AEMA, and NRDC filed the Complaint against NYISO, challenging NYISO’s imposition of BSM on SCRs on the grounds that they interfere with legitimate state objectives. The parties requested a blanket exemption from BSM for all SCRs receiving payments pursuant to a “utility-administered distribution-level Demand Response program.”

The parties requested that the Commission approve an exemption for each of the individual utility-administered, distribution-level programs discussed in the Complaint.

On February 3, 2017, FERC ordered a blanket exemption for all new SCRs, explaining that SCRs had no incentive or ability to affect wholesale market rates. FERC also stated that existing SCRs currently subject to mitigation would not be eligible for the exemption, due to the FERC’s “long-standing practice” of not adjusting mitigation measures after a resource enters the market.

On March 6, 2017, Independent Power Producers of New York, Inc. (IPPNY) filed a request for rehearing, arguing that the SCRs, considered in aggregate, could affect wholesale market rates.

In February 2020, FERC issued an Order revoking the blanket exemption granted in the February 2017 Order.17 FERC also ordered the initiation of a “paper hearing” to determine if any specific New York programs to support SCRs should be exempted.

Peter Dotson-Westphalen coordinated AEMA support on the issue of Buyer-Side Mitigation and Special Case Resources following FERC’s February 2020 ruling and coordinated multiple comment filings with staff from NYPSC, NYSERDA, City of New York, NRDC, and Energy Spectrum. He contributed heavily to the drafting work to the joint comments, as well as the testimony of Katherine Hamilton (on behalf of AEMA) in the paper hearing.

Wild Backstory Aside, House Bill 6 Opens a Door for Energy Efficiency Monetization in Ohio

January 27, 2021

Ohio House Bill 6 had the kind of year that, if it hadn’t taken place during 2020, might have garnered national headlines and caught the attention of Hollywood. 

Before we succumb to the temptation of divulging exploitative details–which include outcries of scandal, bribery, corruption, and racketeering–let’s cover the fundamentals of the bill and what they mean to organizations in the Buckeye State looking to monetize their energy efficiency (EE) projects in 2021 and beyond.

HB 6 was enacted into law on Oct. 19, 2019, and requires all energy efficiency (EE) programs offered by electric utilities in Ohio to end by December 31, 2020.

That utility EE programs are no longer offered in 2021 means any rebate rewards offered by utilities are no longer available to organizations who complete or have completed, EE projects. 

But that DOES NOT mean that organizations and EE project developers in Ohio who help the electric grid by permanently reducing electric demand are shut out from earning revenue for their efforts. 

When one door closes…

In Ohio, organizations and EE project developers can, with the help of a licensed curtailment service provider (CSP), offer their permanently reduced demand (“negawatts”) into PJM’s capacity market, the Reliability Pricing Model.

Once the reduced load is accepted into the market, the organization will earn revenue from PJM for four years after the project was completed. 

To learn more about monetizing energy efficiency projects in PJM in the wake of Ohio House Bill 6’s enactment, click here.  

To learn more about the wild ride House Bill 6 had, Google it and pick from any number of vitriol-laced articles that show up on the first page. 

Fun as it may be to shine a light on the mudslinging around HB 6, it’s not our place at The Current to feed the political maelstrom. We’re here to inform, so you can make educated energy management decisions.

That said, you might want to make sure you do your reading on HB 6 indoors and away from the windows. There is a lot of lightning out there right now.

Arizona’s Largest Utility Ramps its Demand Response program to Pursue Carbon-Free Mission

January 06, 2021

The largest electric utility in Arizona is making strides toward a more sustainable future and it’s clear demand response is part of the plan. 

Arizona Public Service (APS) is the owner and operator of the country’s largest producer of carbon-free electricity–the Palo Verde Generating Station. 

Currently, the utility generates clean, reliable electricity for 1.3 million homes and businesses in 11 of Arizona’s 15 counties and boasts a current energy fuel mix that is 50 percent clean. 

50 percent clean energy in 2021 is impressive enough, but APS CEO Jeff Guldner sees an even cleaner future and has pledged to cease all coal-fired generation in the APS service territory by 2031 and for the utility’s fuel mix to be 100 percent carbon-free by 2050. 

To get there, APS plans to call on a generation portfolio that is 45 percent renewable in just nine years. 

To help bridge the present and future, APS is counting on its own Peak Solutions demand response program to ensure its grid remains reliable when stressed with heavy electrical demand.

Launched in 2010, the Peak Solutions program engages commercial and industrial customers in voluntary energy conservation measures when demand for energy peaks on APS’s system, particularly during Arizona’s scorching summers.

The program also helps maintain lower-cost power for all customers.

As APS ramps up its drive to a carbon-free future, they’re also ramping up their demand response program and the financial rewards participating commercial and industrial organizations will earn for voluntarily reducing their electricity consumption when the demand on the APS grid is high. 

The APS Peak Solutions aims to include participants both small and large evidenced by its minimum load commitment of just 10 kW instead of the more customary 50 kW minimum required by most commercial demand response programs in the US. 

By not having any penalties for non-performance, another atypical demand response program parameter, APS is further making Peak Solutions attractive to organizations who have never before participated in demand response. 

APS’s CEO Jeff Guldner knows that plans and programs aren’t enough to attain a sustainable future in Arizona.  “Achieving and realizing the full benefits of a completely clean energy mix will take partnership,” he said in APS’s published clean energy commitment document,  “It’s something for all of us, by all of us.”

To learn more about demand response and the APS Peak Solutions program, click here.

Case Study: Batteries Included: Creating Value with Behind-the-Meter Storage

October 26, 2020

From grid scale to residential rooftop solar, battery energy storage systems hold the promise of a decentralized, decarbonized, and digitized energy future. They offer operational flexibility, encourage deploying renewable assets, provide financial benefits to owners and third parties alike, and promote both grid stability and customer sustainability. In this new white paper, “Batteries Included: Creating Value with Behind-the-Meter Storage,” Rob Windle, CPower Executive Director, Distributed Resources, discusses the many factors that ensure success for battery energy storage systems.

New England Seeks to Balance Renewables and Grid Reliability

September 01, 2020

Grid Operators in the US deregulated energy markets need only look west to California and the Golden State’s recent barrage of rolling blackouts for a reminder of how an ambitious but unchecked drive to a renewable fuel mix can threaten grid reliability.

California’s charge over the last two decades toward a carbon-free future has led to a flood of solar resources fulfilling the state’s electric demand during the day. 

That’s the good news.

That drive has also led to a phenomenon known in the energy industry as the “duck curve” in the evening when solar resources go offline and demand for electricity ramps to consumption levels that challenge the grid on a daily basis.  

That’s the not-so-good news. 

The duck curve (named so because the ramp in daily evening demand when graphed on a 24-hour consumption chart resembles the neck of a duck) isn’t new. 

The “Duck Curve” was coined in the mid-2010s and shows the effects of demand on California’s grid spiking in the evening when solar goes offline.

For years, in fact, energy markets outside of California have cited the graphed duck’s increasingly bulging belly (indicating a yearly increase in solar resources fulfilling daytime demand) as a case-in-point on how renewable intermittency is both a threat to grid reliability and a challenge for energy markets seeking to evolve their fuel mixes away from traditional fossil fuels.  

Energy storage, long hailed as a panacea whose realization was until recently perpetually dismissed as being a few years away, has arrived as an affordable resource, perfectly suited to satisfy progressives’ ambition and grid operators’ reliability concerns.

The question in 2020 and beyond is this: how can energy markets evolve to allow storage resources to participate and help offset the inevitable intermittency of increasingly popular renewable resources such as solar and wind? 

New England may have the answer in its lineup of demand response programs at both the ISO and utility levels. 

Daily Dispatch Demand Response

New England utilities National Grid, Eversource, and Unitil have introduced a new demand response program called Daily Dispatch. 

The program complements the utilities’ highly successful Connected Solutions demand response program and aims to further reduce peaks on their distribution systems.

Daily Dispatch is designed to allow energy storage (batteries, thermal storage) to participate because of the resource’s ability to be dispatched frequently and quickly in response to rising peaks.

The Daily Dispatch program runs during the summer from June through September. The program is intended to be dispatched daily (as the name suggests)  with anywhere from 30-60 events each year during the hot months of July and August. Each event is expected to last about two to three hours.

The new program has an attractive incentive of $225-300 per kW per summer. Customers’ compensation will be based on their average curtailment amount for all the events that are called during the summer.

On-Peak Demand Response

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

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, cogeneration 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.

Potential for Multiple Revenue Streams

New England organizations can participate in multiple demand response programs. 

That means that organizations with storage resources are in a prime position to open multiple revenue streams through demand-side energy management. 

The New England energy market is evolving toward a fuel mix that features less coal and more renewables. 

By introducing ISO and utility level demand response programs that allow for storage participation, the market is aiming to avoid grid reliability woes brought about by resource intermittency.

Organizations with battery storage devices not only have a leg up in the race to superior resilience, but they also have a flexible, dispatchable resource the grid operator and electric utilities recognize is valuable and are willing to handsomely compensate in times when the grid is stressed or electricity prices are high. 

Watch CPower’s Jobin Arthungal and Mat Tuttelman explain everything your organization needs to know about the New England energy market in the 2020 State of Demand-Side Energy Management in New England video-on-demand. 

ERCOT’s Effective and Lucrative Last Bastion Against Blackouts

August 18, 2020

Texans love a good fight, especially if there is a lot riding on the outcome and the battle comes down to the wire only to be won in the waning seconds by the last fighter standing. 

Maybe that’s why ERCOT’s Load Resource demand response program has been a favorite of commercial organizations in the Lone Star state over the last few years. 

As we’ve discussed in a previous article on the ERCOT’s protocols for demand-side resources, dispatching Load Resource is the grid operator’s last line of defense before initiating rolling blackouts. 

When demand approaches what the grid can supply within 3,000 MW’s, ERCOT takes action.
7 levers are used by ERCOT before they have to call blackouts (BO’s).

Load Resource has consistently been ERCOT’s most rewarding demand response program. Look no further than 2019 for proof.  

In 2019, a year which saw ERCOT call its first demand response events in half a decade, the program not only paid extremely well,  but participants were never called to curtail their loads. 

In the demand response events on August 13th and 15th of 2019, grid balance was restored before Load Resources were needed. Still, Load Resource participants earned revenue 1) for being available to curtail and 2) because of the spike in real-time pricing that reached $9,000/MWh. 

The year Load Resource had in 2019 embodies how economic drivers of the Texas energy market are working to keep the grid reliable, demand response participants happy, and electricity rates relatively low for ratepayers.

What kind of year will 2020 be for Load Resource?

Predicting the future is usually a fool’s errand, especially when it comes to the energy industry. But let’s give it a shot anyway.

Electric demand continues to rise in Texas and ERCOT has taken measures to keep its grid reliable. The reserve margin is growing and a new demand response program (ERCOT Contingency Reserve Service or ECRS) will eventually be added to the ISO’s arsenal in 2024.

But if we look at the last five years, Load Resource has been called a grand total of zero times. All the while, participants have earned significant revenue for being available to help the Texas electrical grid if needed.

Sometimes the past helps predict the future. In that case, it looks like 2020 will be another strong year for Load Resource in Texas. 

This is, after all, 2020. The summer of the wildest year we can remember isn’t over yet. But the Texas grid has been up for the fight so far this year. If the last few rounds get particularly punishing, Load Resource is standing guard as the grid’s lucrative last bastion. 

To learn more about ERCOT’s Load Resource program as well as the state of the energy market in Texas, join CPower’s Joe Hayden and Mike Hourihan on September 3, 2020 (changed from Aug 27 in response to Hurricane Laura), for a 60-minute webinar: The State of Demand-Side Energy Management in Texas for 2020. Register HERE. 

 

Are You Earning Revenue From Your Energy Savings? (Webinar)

July 23, 2020



Are You Earning Revenue From Your Energy Savings?

Has your organization completed an energy efficiency project in the last two years? Are you planning on completing a project before June of 2021? If the answer is yes – you are likely eligible for earnings in addition to the savings your project is already delivering for up to the next four years.

 

Join Kelly Mallin & Jim Hooven from SJI Energy Advisors and its partner, CPower Energy Management, for a 60-min webinar to understand how you can receive these lucrative incentives. CPower can measure and verify your permanent load reduction and submit it to PJM (your regional transmission operator). And your organization begins receiving revenue payments. It’s that easy. No curtailment, no shutdown, no operational changes, no production or customer impact. Just revenue for work you have already completed!

 

Watch this webinar to learn more about:

  • Eligible incentives by state and utilities in PJM
  • Earning potential for past projects
  • Project data submission through CPower
  • How to generate additional revenue from other curtailment programs

PSC Order on NY Utility DR Program Changes for Summer 2020 – Market Minute (Video)

June 02, 2020



 

On May 14th, in response to COVID-19 related challenges and recommendations raised by stakeholders,  the New York Public Service Commission issued an Order directing most of the utilities to implement several changes to their Dynamic Load Management (DLM) tariffs to become effective as of June 1st. These changes will impact the Commercial System Relief Program (CSRP) and the Distribution Load Relief Program (DLRP) for Summer 2020 and are intended to increase program flexibility for DR aggregators and participants.

The PSC Order directs the utilities to make the following changes to their DLM tariffs:

First, there will be an additional enrollment window to allow new participants to participate in the programs in July through September if enrollments are submitted by June 1st.

Second, for customers currently enrolled will have an opportunity to adjust their committed kW reduction amounts for July through September if this is submitted by June 1st.

Third, testing will occur only if an event has not already occurred, and the PSC has directed utilities to not administer a test before July 1st.

Lastly, for customers that have utility interval or AMI metering installed but have not been able to establish communications between the meter and the utility will be provisionally approved to participate, pending establishment of the necessary communications and providing that meter data for the CBL baseline calculations and test/event performance can be retrieved to assess program performance for settlement and payment.

These changes will be applicable to all utilities within New York, except for PSEG-LI. The PSC Order directs Department of Public Service staff to work with LIPA/PSEG-LI staff to see if similar changes can be implemented for their CSRP and DLRP programs for this program season.

If your organization is currently participating in one or both of the CSRP and DLRP programs in 2020, or had opted not to enroll in these programs due to operational and electric load changes for the season, you now have one more opportunity to enroll to participate in July through September, or to adjust your level of participation through adjusting your enrollment value.

If you have any questions or would like to enroll, or adjust your current enrollment amount, in the CSRP or DLRP programs by June 1st, or have any other New York energy question, contact CPower and we’ll help you in any way we can.

On May 14th, in response to COVID-19 related challenges and recommendations raised by stakeholders,  the New York Public Service Commission issued an Order directing most of the utilities to implement several changes to their Dynamic Load Management (DLM) tariffs to become effective as of June 1st. These changes will impact the Commercial System Relief Program (CSRP) and the Distribution Load Relief Program (DLRP) for Summer 2020 and are intended to increase program flexibility for DR aggregators and participants.

The PSC Order directs the utilities to make the following changes to their DLM tariffs:

  1. Enrollment – an additional enrollment window has been added. New enrollments must be submitted by June 1st for participation in the CSRP/DLRP for July through September.
  2. Enrollment Adjustment – participants may adjust their committed kW to the CSRP and DLRP programs by submitting updated enrollments by June 1st, to become effective July 1st.
  3. Testing – utilities have been directed to not administer tests in their programs until July 1st at the earliest, and to not administer a test if an event has already been called.
  4. Metering – customers that have utility interval or AMI metering installed but have not been able to establish communications between the meter and the utility will be provisionally approved to participate, pending establishment of the necessary communications and providing that meter data for the CBL baseline calculations and test/event performance can be retrieved to assess program performance for settlement and payment.

These changes will be applicable to all utilities within New York, except for PSEG-LI. The PSC Order directs Department of Public Service staff to work with LIPA/PSEG-LI staff to see if similar changes can be implemented for their CSRP and DLRP programs for this program season.

If your organization is currently participating in one or both of the CSRP and DLRP programs in 2020, or had opted not to enroll in these programs due to operational and electric load changes for the season, you now have one more opportunity to enroll to participate in July through September, or to adjust your level of participation through adjusting your enrollment value.

If you have any questions or would like to enroll, or adjust your current enrollment amount, in the CSRP or DLRP programs by June 1st, or have any other New York energy question, contact CPower and we’ll help you in any way we can.