Page 1101 – RTO Insider

May 17, 2020

SPP Briefs: Week of May 11, 2020

SPP’s Market Monitoring Unit last week released the final version of its 2019 State of the Market report and a study conducted for state regulators working on improving issues across the MISO seam.

The MMU shared a draft of the market report in April with the Board of Directors. (See “Lowest Prices Ever for Integrated Marketplace,” SPP Board/Members Committee Briefs: April 28, 2020.)

The Monitor said SPP’s energy prices were the lowest since its Integrated Marketplace went live in 2014. Day-ahead prices averaged about $22/MWh and real-time prices about $21/MWh, both down from $25/MWh in 2018.

The flow for the coordinated transaction scheduling process across the SPP-MISO seam | *Market Monitoring Unit*

The report also lists several new market-improvement recommendations, including strengthening price formation during emergencies and scarcity events, incentivizing capacity performance, and updating and improving outage coordination methodology.

The MMU will discuss the report with stakeholders during a May 26 webinar.

The second report analyzes coordinated transaction scheduling (CTS) as part of the MMU’s work for the SPP Regional State Committee and the Organization of MISO States’ Liaison Committee.

The study estimated that the RTOs are incurring $9.4 million to $11.2 million in economic inefficiency losses because they lack a CTS product. The MMU looked at cost and benefit information from other markets’ CTS products and estimated the potential increase in flow across the SPP and MISO seam.

The MMU said several roadblocks are hampering efficiency gains, such as transmission fees and non-energy market charges for CTS transactions, ramp-rate restriction on net scheduled interchange, and price forecasting accuracy, volatility and uncertainty.

Potomac Economics, MISO’s Independent Market Monitor, has also filed a study report with the regulatory committee that evaluates the market-to-market (M2M) coordination processes. The M2M process allows the RTOs to manage together congestion on transmission constraints that affect both SPP and MISO.

The IMM study says that “even modest improvements” in the M2M process can lead to large changes in congestion costs and efficiency savings. The RTOs’ congestion costs during the one-year study period exceeded $150 million.

WEIS Market Participants Prep for Tests

David Kelley, SPP’s director of seams and market design, told participants in the RTO’s nascent Western Energy Imbalance Service (WEIS) market to “buckle up” with market trials just weeks away.

“Ensure your systems are working,” Kelley told members of the Western Markets Executive Committee during a webinar Friday. “You will start to get flooded with a lot of information around market trials. It’s about to be a wild ride.”

In July, WEIS market participants will conduct connectivity testing to ensure their systems can “talk” with SPP’s. Structured and unstructured testing will be held from August through Nov. 20.

The WEIS market, with eight participants signed up, is scheduled to go live in February 2021. Kelley said the implementation project is in yellow status only while it waits on a second release of its markets software.

SPP, MISO Begin Year 5 of M2M Process

SPP and MISO began their fifth year of M2M operations across their seam by continuing the trend set during the first four years, with SPP again benefiting from settlements in its favor.

The RTO piled up $2.77 million in M2M settlements in March, raising its 61-month total to $76.35 million, staff told the Seams Steering Committee on Wednesday. M2M settlements have accrued to SPP for 45 months since the two RTOs began the process in March 2015.

SPP has piled up $76.35 million in market-to-market settlements from MISO since March 2015. | *SPP*

Temporary and permanent flowgates on the RTOs’ seam were binding for 681 hours during March. Temporary flowgates accounted for 429 of the binding hours.

May 15, 2020

PJM Refining Default Service Rules Under MOPR

PJM officials have revised some of their proposed rules for applying the minimum offer price rule (MOPR) to state default service procurements in response to stakeholder feedback.

At the Market Implementation Committee meeting Wednesday, PJM attorney Chen Lu outlined a revised definition of an “entity providing default retail service.” The new definition defines the term as any entity “providing default retail service, including but not limited to a load aggregator or power marketer that enters into a contract or similar obligation with an electric distribution company to provide default electric services for retail customers who do not participate in the selection of a competitive retail provider that has been granted the authority.”

Exemption Criteria

Lu also provided a revised “state subsidy definition” exempting “bilateral transactions” used to fulfill default retail service obligations from the MOPR if the state default procurement auction meets certain criteria:

being subject to independent oversight by a consultant or manager who certifies that the auction was conducted through a nondiscriminatory and competitive bidding process;
does not impose conditions based on the ownership, location, affiliation or resource type — except for meeting state renewable portfolio standard requirements;
does not require bilateral transactions to be sourced from any specific resource or resource type to satisfy retail supply obligations; and
costs can be avoided by retail customers who elect to obtain supply from a competitive retail supplier.

Wednesday’s two-and-a-half hour discussion picked up on talks at the MIC’s special session May 6 over straw proposals attempting to address Paragraph 386 of FERC’s April 16 rehearing order of its Dec. 19 order expanding the MOPR. That paragraph said that state procurement auctions are a form of a state subsidy because they provide a payment or other financial benefit to capacity resources that are part of a state-sponsored or state-mandated process. PJM must make a compliance filing in response to the April order by June 1.

Lu said the RTO reconsidered the definitions based on stakeholders’ opinions that their “potential compliance approach” was “likely too complicated and potentially unworkable.” (See PJM, IMM Present MOPR Rules for State Procurements.)

Jason Barker of Exelon said Wednesday he was “concerned” by the new language and requested PJM consider how the selected wording would impact businesses participating in the provider of last resort (POLR) auctions. He said focusing the exemption on the existence of bilateral contracts could have major implications on most capacity auctions because some POLR auction suppliers also own generation.

“You could have the potential impact of tens of thousands of megawatts of potential supply into those auctions,” Barker said. “We would certainly ask you to sharpen the pencils on that point.”

Lu said the new language was proposed as another alternative after hearing stakeholder concerns at the May 6 special session and that the RTO has not finalized its decision on the issue.

PJM Default Service Rules — NRC Chairman Kristine L. Svinicki tours Energy Harbor’s Beaver Valley nuclear plant. Energy Harbor announced April 30 that it was awarded 18 tranches in the recent Pennsylvania provider of last resort (POLR) auction. | *NRC*

Consultant Roy Shanker said he liked the new wording, calling it a “simple solution” that seemed to address concerns voiced by Sam Randazzo, chairman of the Public Utilities Commission of Ohio, at the May 6 meeting. Shanker said a simple way to look at the new language was that if the auction is asking for more than megawatts or megawatt-hours, then it’s discriminatory.

“This is an efficient way to send the right signal about who you are trying to exempt,” Shanker said.

Gary Greiner, director of market policy for Public Service Enterprise Group, said he was taken aback early on in Wednesday’s discussion as to what constitutes a “bilateral transaction.” In the commercial world, “bilateral” means direct one-to-one transactions between two parties, he said.

The issue, Greiner said, is that a generation-owning entity typically engages in multiple POLR contracts and other supply arrangements, and that anything that happens within a portfolio could be considered a bilateral transaction. He said there’s nothing that doesn’t come through a bilateral transaction that is fulfilling an obligation in a default service program. Theoretically, he said, just about anything could be exempt.

“It’s impossible to paint the megawatts that are being used to fulfill the state retail service obligations,” Greiner said. “It’s just all baked in there.”

Marji Philips, LS Power’s vice president of wholesale market policy, said she viewed the new language as clearer than what PJM initially proposed. Philips said if stakeholders take the FERC order to its literal conclusion, then no generation owner could do any hedging in the PJM market, whether it’s with public power or a load-serving entity.

Philips said what PJM could do as a workaround is having the ability to track capacity obligations for transparency.

“What PJM is proposing is a good solution to what is a financial market that FERC has told them they have some obligation to oversee,” Philips said. “I think it really tries to solve a very difficult conundrum.”

Sticking to the Order

But Philips and David “Scarp” Scarpignato took issue with PJM’s plan to introduce in its June 1 compliance filing a new term, “re-entry capacity resource with state subsidy,” for resources that return to the capacity market after failing to offer into a BRA.

MIC Chair Lisa Morelli said such resources would have a MOPR floor price of net CONE, like new-entry resources. However, PJM is proposing to treat them like existing resources regarding the penalty for accepting a subsidy after electing the competitive exemption. It would require them to forfeit capacity revenues for the delivery year but not subject them to the asset life ban applied to new resources that violate the competitive exemption.

Because FERC was “silent” on this particular issue, Morelli said, PJM decided banning such existing resources from the capacity market for their lifespan “seemed a bit harsh.”

Scarp said the new definition appeared to be an attempt to “improve upon” the order.

“This is kind of pushing the envelope on whether you’re complying with the order or not,” he said. “I’m worried you’re going to unintentionally cause a delay in getting a final order out of FERC. You’re risking FERC coming back and ordering a third compliance filing.”

Morelli said failing to address the issue would be unfair to resources that had accepted subsidies under rules in effect before the December FERC order expanding the MOPR. “We’re not trying to get cute with the language, but it’s a very real issue,” she said.

Philips said PJM’s proposal “so clearly contradicts what the order says.”

“As Scarp noted, we have plenty of time to change the rules. As it is, the auction is on a very tight schedule,” she continued. “I would encourage PJM to stick to the issues and not reinterpret what it thinks is right.”

May 15, 2020

NYPSC Launches Grid Study, Extends Solar Funding

The New York Public Service Commission on Thursday voted unanimously to undertake a study to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals (20-E-0197).

“In my view, this is a timely, critical and thoughtful plan to start to modernize our grid … to meet our future needs, including the need to deliver the new clean energy called for by the state’s agenda,” PSC Chair John Rhodes said.

The study was mandated by a budget amendment passed last month that created a new siting agency for renewable energy projects. The New York State Energy Research and Development Authority will collaborate with the Department of Environmental Conservation and the Department of Public Service (DPS) to develop build-ready sites for renewable energy projects. (See NY Renewable Supporters Push for New Siting Agency.)

NYPSC Grid Study — 2019 NYCA energy production by zone | *NYISO*

Under the new order, transmission investments that the commission determines must be “completed expeditiously” are referred to the New York Power Authority for development and construction. Other projects are to be selected for implementation through NYISO’s public policy planning process.

“I look most importantly to the New York ISO, who has been a leader in appropriate tactical studies as it relates to the grid, especially with the reliability and resiliency aspects, and the studies that they are currently undertaking,” Commissioner Diane Burman said. “I do look to them as an important component of really critical evaluation and analysis that will be helpful.”

Commissioner John Howard said that in “the process of turning legislative goals into policy … we should be as cautious with other people’s pocketbooks as possible. This rebuilding of the grid could be enormously expensive … there’s always the temptation to gold-plate the system.”

Extended Run for NY-Sun

The commission also authorized an additional $573 million in funding to support the state’s goal to procure 6 GW in distributed solar generation by 2025 and extend the NY-Sun program to 2025, as petitioned by NYSERDA in November (19-E-0735).

DPS staff determined that the state is on track to achieve the original goal of 3 GW by 2023, with more than 2,410 MW in service in New York and more than 1,200 MW currently in development.

The NY-Sun initiative was part of the Clean Energy Fund created by the commission in 2016, which established utility collections from ratepayers to support the overall $960 million funding requirement.

Burman was the sole vote against the program extension, as she was in last month’s authorization for NYSERDA to solicit up to 2,500 MW of offshore wind energy this year. (See NYPSC Greenlights 2,500-MW Offshore Wind RFP.)

“I am really concerned about not only extending the program through 2025, which means the [ratepayer] collections continue, but also allocating additional funding — albeit it may be from reallocating uncommitted funds — and also then teeing up that we may be looking at new funding in a clean energy review,” Burman said.

Rather than indicate in the order that the PSC expects NYSERDA to report back on the impacts of the COVID-19 pandemic on the distributed solar industry, she said the commission should be asking the agency to report on that now.

“Doing this now really concerns me because, as we’ve seen, even from last session, what we saw as a need to move quickly on something didn’t necessarily mean that NYSERDA did,” Burman said.

Following the commission’s offshore authorization last month, NYSERDA said in a statement that it would not be rushing to put out a request for proposals amid the pandemic.

“My concern is that we have large-scale renewables solicitations on pause; we have the offshore wind solicitation on pause; we have a number of things that are on pause; and so the only thing not on pause is the movement of funding and the extension of programs that have ratepayer dollars attached to them,” Burman said.

Commissioner Tracey Edwards joined the call for accountability.

“I’m concerned that what we have in here that benefits the low- and moderate-income communities actually happens,” Edwards said.

She asked DPS staff to talk to NYSERDA about making the annual clean energy review into a quarterly review.

“I think it’s just critical,” she said. “Low-income communities get the brunt of environmental injustices right now, so if there are programs that are going to be put in place, we need to make sure that they are in fact working.”

May 14, 2020

FCC Opens 900-MHz Band for Broadband Use

The Federal Communications Commission voted Wednesday to make part of the 900-MHz spectrum available for companies in the utility, transportation, manufacturing and petrochemical sectors to develop “critical wireless broadband technologies and services.”

The 900-MHz band is currently reserved for narrowband land mobile radio communications by those industries. According to a press release, the FCC’s decision would make 6 MHz available for broadband licenses on a county-by-county basis, while the remaining 4 MHz would remain reserved for narrowband operations.

As part of the action, the commission will partially lift the 900-MHz application freeze so that existing licensees may relocate their operations as part of a transition plan. Utilities will be exempt from mandatory relocation. It will also modify the Association of American Railroads’ 900-MHz license, which gives it full use of the spectrum in areas surrounding rail lines in the contiguous U.S. Under the new rules, the AAR will be limited to the 4 MHz of narrowband frequencies.

FCC Broadband Use — FCC Chairman Ajit Pai | *FCC*

Opening up the 900-MHz band for broadband use is expected to provide a range of benefits to utilities and other users that will not have to use noisy commercial spectrums. Potential uses of the new spectrum by the electric industry described by commissioners include cybersecurity applications, real-time damage notifications and more efficient routing of energy.

Industry reactions to the change have been largely positive, with John Hughes, director of network engineering for Ameren, saying the decision “paved the way for [Ameren] to deploy a smarter, stronger and more secure communications network with far greater bandwidth.” The Enterprise Wireless Alliance, which proposed the rule change alongside Anterix in 2014, also applauded the move, saying that businesses and critical infrastructure entities “deserve access to spectrum capable of providing broadband solutions to their industrial tasks.”

“The order we adopt today strikes a balance between the goals of expanding access to broadband wireless communications services and maintaining access to sufficient spectrum for existing narrowband services,” FCC Chairman Ajit Pai said in a separate statement. “Our plan today not only will serve the existing users of the band, but also will rely on their unique expertise to make the transition to broadband possible.”

Recent FCC decisions affecting the electric industry include last month’s vote to open a portion of the 6-GHz band for unlicensed use. That decision was intended to improve rural connectivity and free up more space for use by consumer Wi-Fi devices. But utilities objected to the move, fearing disruption to their communications in the spectrum. (See Utilities Alarmed as FCC Opens 6 GHz Band to Wi-Fi.)

May 14, 2020

NERC Board of Trustees/MRC Briefs: May 14, 2020

NERC’s Member Representatives Committee and Board of Trustees met via conference call on Thursday after in-person meetings in D.C. were canceled because of the COVID-19 pandemic.

Interviews Planned for Potential Canadian Trustees

The Nominating Committee has prepared a slate of six candidates to replace former Trustee David Goulding, who retired in January, and plans to hold interviews next month. The interviewing panel will include board Chair Roy Thilly, Vice Chair Kenneth W. DeFontes Jr., MRC Chair Jennifer Sterling, MRC Vice Chair Paul Choudhury and Trustee Colleen Sidford.

Along with Goulding’s replacement, the committee is also searching for a trustee to fill the seat of Jan Schori, who will retire at the end of 2020. As Goulding’s retirement leaves the board with only one Canadian trustee, and it is required to have at least two, the team decided to speed up the search for a successor who can be seated as soon as possible. (See “Search Begins for New Board Members,” NERC MRC Briefs: Feb. 5, 2020.)

NERC Board of Trustees — Left to right: NERC Trustee Robert Clarke, Chair Roy Thilly, Vice Chair Kenneth DeFontes and CEO Jim Robb at the last in-person Board of Trustees meeting in February 2020. | © *ERO Insider*

For Schori’s replacement, the committee has engaged executive search firm Russell Reynolds and hopes to schedule interviews in early November. The interviews will be conducted in person if possible, but the committee is also exploring the option of remote interviews. Next month’s interviews are already set to be conducted electronically.

Align Expenditure Moves to FERC for Approval

The board agreed to request a $3.8 million budget variance from FERC to account for delays in NERC’s Align software project, intended to improve and standardize compliance monitoring and reporting processes across the ERO Enterprise.

Align was scheduled to be released in September 2019 but was delayed several times in order to include additional security features in the initial release. The delays caused the cost of the project to rise beyond its original estimate by up to $2 million, NERC interim CFO Andy Sharp said during the MRC conference call in April. (See Align Tool Set for 2021 Rollout.) The board also approved this expenditure at Thursday’s meeting.

The budget variance will be partially covered by a projected $1 million surplus from NERC’s operating contingency reserves for this year, but the majority will be financed by $2.8 million in debt. The organization will pursue a 60-month term rather than the typical 36 months, as the current low interest rates mean overall servicing costs will be the same or lower than previous projections of debt service for this year.

“I had asked the question earlier … as to whether we should really be thinking about doing financings for any of this, and the answer that came back was ‘yes,’” said Bill Gallagher, special projects chief for the Vermont Public Power Supply Authority. “I’ve always been looking at NERC to be debt-free, but I guess in this particular set of circumstances, it probably makes sense” to approve the debt.

Other Approvals

The board approved action on the following reliability standards:

Adopt reliability standard CIP-002-6, governing bulk electric system cyber system categorization, and retire CIP-002-5.1a per the recommendations of the CIP Version 5 Transition Advisory Group.
Withdraw proposed reliability standard VAR-001-6, covering voltage and reactive control. The decision would leave currently effective standard VAR-001-5 in place.

Board members also approved revisions to the current pro forma delegation agreements between NERC and the regional entities, which are set to expire at the end of the year. The revisions would include:

eliminating maps of RE boundaries in favor of textual descriptions, which the organization feels would allow more precision in assigning registered entities to specific REs;
clarifying requirements regarding the nomination of independent board members;
removing outdated language in light of the dissolutions of the SPP RE and Florida Reliability Coordinating Council;
prohibiting stakeholders from leading RE board compliance committees;
allowing REs greater flexibility regarding the use of funds collected through penalties; and
clarifying that delegation agreements may be terminated earlier than the end of the five-year term as long as written notice is provided of at least one year.

COVID-19 Prompts Further Meeting Changes

With future developments in the pandemic still uncertain, the board has decided that its next meeting, as well as the MRC’s, will be carried out via conference call again. The meetings were previously scheduled to take place Aug. 19-20 in Vancouver, Canada.

Chair Thilly said the board has deferred a decision on its final meeting of 2020, planned for Nov. 4-5 in Atlanta, while it monitors the progress of the COVID-19 response and recovery. The leadership is considering several options for the meeting that include going forward as planned, holding an online session again, or restricting in-person meetings to board and MRC members only, with others listening in via conference call.

“Whether that will be possible to establish [while maintaining] social distancing, or whether any meeting will be possible at that time, is simply unknown. But we will try to make that decision in a timely way so that people can prepare,” Thilly said.

May 14, 2020

NERC, FERC Release Pandemic Response Resource

In light of the COVID-19 outbreak, NERC, FERC, the Department of Energy and the North American Transmission Forum (NATF) have created a resource to help entities develop response plans for pandemics and epidemics.

The Epidemic/Pandemic Response Plan Resource, released this week, is intended to “help utilities create, update or formalize” plans for response and recovery from future disease outbreaks, which are recommended as a complement to an organization’s overall business continuity plan. Objectives of pandemic response plans should include:

Health and safety — maintaining a healthy work environment for employees while protecting their safety and that of their families;
Security — maintaining cyber and physical security, with “special considerations to the distractions and challenges imposed by an epidemic/pandemic”;
Communications — providing clear direction on plan details and execution, while ensuring effective communication to personnel, staff and the wider community; and
Recovery — resuming normal operations as permitted by conditions and the available workforce.

Specific recommendations include designating specific members of entities’ senior management to emergency response teams and describing actions to be taken by such teams, including tracking progress of a pandemic; coordinating the tracking and status reporting of infections and absenteeism in the workforce; and ensuring employees are informed of the development of the situation. The document also advises on specific preparatory measures such as planning for widespread health screening; identification of essential positions and determining their work schedules and compensation; and planning for quarantining and sequestering employees.

NERC FERC Pandemic Response — The Atlanta Financial Center, site of NERC headquarters | © *ERO Insider*

In a press release, NERC noted that the progress of pandemics can be hard to prevent and emphasized the importance of “flexible and scalable management strategies and preventative measures taken in advance” of such events. The organization said that while the resource was developed for the electric industry, other critical infrastructure operators may be able to benefit from its information.

“Preplanning for events such as the current pandemic ensures staff is healthy and safe, while still sustaining their effectiveness,” said Mark Lauby, NERC senior vice president and chief engineer. “This resource can provide a road map for organizations to create or supplement their existing plans.”

The pandemic response resource is the latest in a series of actions by NERC and FERC to assist utilities with their response to the coronavirus crisis. NERC’s response began in earnest with the issue of a Level 2 alert in March, and the organization last month expressed confidence that the industry is “taking aggressive steps to confront” the pandemic. (See Industry Pandemic Prep Encouraging, NERC Says.)

NERC itself has activated its business continuity plan and shifted to a “full remote work posture,” which is expected to continue through July 4. CEO Jim Robb said last month that the organization had confirmed three cases of the virus among its staff, with “no evidence of any community spread” to other ERO participants. (See “Robb Delivers COVID-19 Update,” Align Tool Set for 2021 Rollout.) External meetings through June have been canceled or converted to conference calls.

NERC and FERC have also taken steps to relax compliance burdens for utilities via the use of regulatory discretion. The actions announced in March include postponing on-site activities such as audits and certifications, as well as lenience toward delays in maintaining personnel certification and failing to perform required periodic actions. (See FERC, NERC Relax Compliance in Light of COVID-19.)

May 13, 2020

EDF Sees ERCOT Value in Demand-Side Solutions

The Environmental Defense Fund on Tuesday released a report on ERCO T‘s energy-only market that concludes it can meet future demand growth, increase grid resilience and keep energy costs down through demand-side solutions.

ERCOT Demand-Side Solutions — Alison Silverstein | © *RTO Insider*

Titled “Resource Adequacy Challenges in Texas: Unleashing Demand-side Resources in the ERCOT Competitive Market” and written by energy consultant Alison Silverstein, the re p ort posits that ERCOT’s market design “works efficiently and effectively, and it should be maintained.”

The EDF report also says that distributed energy resources, such as solar and storage, and demand-side measures, such as energy efficiency and automated and price-responsive demand, can respond to prices as well as to grid management signals.

“These assets should be used to de-risk the electric system by reducing peak load and ancillary service needs,” Silverstein writes. “All of these resources can be coordinated and integrated with advanced monitoring, forecasting, analytics, communications and controls to integrate and balance demand with supply for reliable, affordable and sustainable electric service.”

“The whole demand-side was a little bit of a surprise,” Silverstein told RTO Insider.

She said she began the report by considering whether competition within ERCOT’s market would continue to work and whether there would be “fingernail chewing every summer,” given the ISO’s 10.6% reserve margin. (See ERCOT Se e s Summer Repeat: Record Peak, Tight Reserves.)

“But when I started looking at the characteristics of the demand-side today as we get more energy efficiency and automated demand-side capabilities, and we get more photovoltaic and battery storage on the customer side, we have the potential to make demand dispatchable,” Silverstein said. “We could manage demand to better balance supply, which is dispatchable and intermittent. Rather than put all the pressure on supply alone, demand-side measures offer many benefits to customers, besides holding down the prices.”

Demand-side resources can reduce the burden and cost of assuring adequate supply and flexibility services and also protect customers while improving system and community resilience, she said.

As Silverstein was buttoning up the report in February, the COVID-19 coronavirus was upending life for much of the world. Soon thereafter, Texas was hit by a collapse in oil and gas prices, thanks to a production price war between Russia and Saudi Arabia, and a 30% drop in U.S. oil consumption.

Texas produces more than 42% of the nation’s crude oil, Silverstein said, but the U.S. rig c o unt has fallen for nine straight weeks to 374. A year ago, 988 rigs were in operation. Texas is home to about half of those rigs, most in the Permian Basin of West Texas. On Tuesday, West Texas Intermediate Crude prices were trading around $25/barrel, a far cry from the halcyon days of $150/barrel oil.

Asked about the oil slump’s effect on the ERCOT market, Silverstein said simply, “It isn’t going to be good.”

West Texas’ oil fields provided the fastest-growing demands for electricity until recently, she said, but as those wells are shut in, both demand and the need for oil field workers will drop. The oil and gas industry accounts, directly and indirectly, for about 1 in 6 of the state’s jobs.

“That means we both lose the direct consumer of electricity and the electricity demand of all those people employed in oil and gas and those jobs they supported,” she said. “It’ll have a huge ripple effect for demand.”

The reduced pressure on demand and prices will lead to the most uneconomical power plants shutting down. “Some of those plants in [ERCOT’s interconnection] queue will vaporize,” Silverstein said, leading to continued operation of older plants.

In the report, Silverstein said both COVID-19 and the oil slump will create long-term shifts in ERCOT demand, leading to a “multi-year” drop in residential and commercial energy use. They will “delay, but not negate” the region’s long-term challenges, she wrote.

“Texas’ energy profile will continue to change and become more complicated,” the report says. “New technologies and energy resources — particularly more demand response and energy efficiency — offer ways to improve resilience, maintain reliability, reduce costs and further modernize ERCOT’s successful competitive market.”

The report outlines four recommendations to maximize demand-side resources’ potential:

Eliminating legislative and regulatory barriers that make it harder or less attractive to deploy demand-side resources, including any barriers to their participation in the ERCOT market;
Relying more heavily on energy efficiency by strengthening standards and requirements and allowing local governments to set more aggressive standards for their jurisdictions;
Requiring that any facilities planning publicly funded renewable energy additions first undergo an energy efficiency audit to ensure the project’s prudent use of funds, a move EDF said would save energy and avoid investing in unnecessary infrastructure;
Supporting local and government investment that creates new funding mechanisms in demand-side management programs and technology.

EDF said the report is the first to clearly outline the relationship between supply and demand for the state’s resource adequacy and present how demand-side resources can fit within Texas’ existing market.

John Hall, EDF’s director of regulatory and legislative affairs, said demand reduction has always been part of ERCOT’s market. However, he said, meeting demand continues to be accomplished primarily by increasing generation capacity.

“We cannot build our way out of this,” Hall said in a state m ent. “Demand-side solutions are the cheapest sources of new electricity. They’re certainly cheaper than building new power plants, and they are often more cost-effective than utility scale wind and solar.”

May 13, 2020

NYISO Explores Hybrid Interconnection Processes

NYISO staff on Monday shared with stakeholders proposed interconnection processes for the market participation options the ISO has floated in its effort to integrate hybrid storage resources (HSRs) into its energy and capacity markets.

Kanchan Upadhyay and Amanda Myott, energy and capacity market design specialists, respectively, presented the ISO’s ideas to the Installed Capacity/Market Issues Working Group during a teleconference.

The ISO is proposing three interconnection options for HSRs:

Option 1 would allow HSRs to participate in the markets as distinct generators that share a point of interconnection;
Option 2 would enable participation through an aggregation model to allow resource components within the HSR that share a point of interconnection to bid as a single resource;
Option 3 would recognize an HSR as a self-managed energy storage resource that receives some or all of its energy from a connected renewable generator. (See NYISO Weighs Market Options for Hybrid Resources.)

Upadhyay covered the potential Energy Resource Interconnection Service (ERIS) process for HSRs. She said that for any new or proposed facilities proposing to interconnect as a hybrid resource, all resources behind the same point of interconnection (POI) could be included in a single interconnection request.

Distinct resources participating under Option 1 would have a separate ERIS for each unit, limited to the minimum of the capability of the inverters or the capability of the respective units.

NYISO Hybrid Interconnection — Examples of capacity resource interconnection service (CRIS) for hybrid storage resources. | *NYISO*

Under the current proposal, “the injection limit of the HSR project must be greater than or equal to the combined capability of all resources within the project,” Upadhyay said. “The ISO is still evaluating a potential enhancement that would enable this option to accommodate HSR projects with an injection limit that is less than the combined capability of its component resources.”

If existing market rules need to be modified, such changes will be developed for a potential vote at the Business Issues Committee by the end of 2020, Upadhyay said.

ERIS Limits

While HSR units may be studied under a single request, they may require separate interconnection agreements since they are treated separately in the market, Upadhyay said.

Aggregate hybrid resources participating under Option 2 would have a single, combined ERIS limited to the minimum of the capability of the inverters or the total capability of the combined units.

Hybrid ESRs under Option 3 would have a single, combined ERIS limited to the minimum of the capability of the inverter or the capability of the storage component of the hybrid resource.

Stakeholders stressed the importance of allowing developers to specify lower interconnection limits than the total potential output of the inverters.

“There could very well be configurations under Option 2 that have multiple inverters, solar paired with storage in quite a few combinations,” said Bill Acker, executive director of New York Battery and Energy Storage Technology Consortium (NY BEST). “I think it was mentioned earlier that there was possibly some work on looking at how that might work with a collection of inverters. We would hope that it wouldn’t necessarily have to be the sum of all the inverters, that you could actually set up a solution like that.”

CRIS Limits

Myott led the discussion on capacity resource interconnection service (CRIS) awards for HSRs, whereby each distinct resource within an HSR may request CRIS individually up to the nameplate of the resource.

Hybrid Interconnection — NYSERDA map shows distributed energy resources around New York City. | *NYISO*

In response to a stakeholder question on the potential enhancement to Option 1 to allocate CRIS between the two resources, Myott said NYISO is investigating the topic in the event they are able to implement an inverter limit.

“We’re thinking through all of the implications in terms of the application and how feasible implementing that would be, particularly in the short term [when] we’re trying to make this option accessible for these types of resources,” Myott said.

The ISO hopes to come back with more details soon but is not sure when, she said.

Aggregate hybrid resources under Option 2 may request CRIS up to the minimum of the inverter limit or nameplate of the components that comprise the HSR. Hybrid ESRs under Option 3 may request CRIS up to the minimum of the inverter limit or nameplate of the storage component, she said.

Myott closed by noting that the ISO is working on responses to various stakeholder questions, which will be addressed at a future working group. Topics include additional information about Northeast Power Coordinating Council reserve requirements; clarification on the “front-of-the-meter” definition; exploration of a possible thermal-plus-storage model; examples with numbers to understand how many megawatts can participate under each market (energy, reg, reserves, capacity) under each proposed option; and clarification on which options the ISO will pursue.

Mitigation Review

Market Design Specialist Sarah Carkner presented an upd a te on the ISO’s comprehensive review of buyer-side mitigation, which is part of the “Grid in Transition” initiative. (See N.Y. Lo o ks at Grid Transition Modeling, Reliability.)

F E RC in February narrowed the resources exempt from NYISO’s buyer-side market power mitigation (BSM) rules in southeastern New York, ordering the ISO to subject storage and demand response to a minimum offer floor in its capacity market. (See FERC Narrows NYISO Mitigati o n Exemptions.)

“We would like to move forward any concept as far as we can this year,” Carkner said. “Ideally, we would like to get the market design complete on any additional concepts for this project.”

May 13, 2020

Stakeholders Urge PJM: Plan `Grid of the Future’

Transmission owners’ supplemental projects totaled almost $3.4 billion in PJM in 2019, more than double the less than $1.5 billion in regionally planned baseline projects, PJM told the Transmission Expansion Advisory Committee Tuesday. It marked the fifth year out of the last six in which supplemental projects exceeded baseline projects.

PJM grid — Sharon Segner, LS Power | © *RTO Insider*

“Supplemental projects undermine the strength of PJM as a regional planner,” LS Power’s Sharon Segner responded after a presen t ation by PJM’s Aaron Berner. “The question in our mind is: Is the right transmission being built?”

She was repeating a position that she and load-side stakeholders have made repeatedly in prior meetings — and that LS Power and dozens of other stakeholders made in a lett e r Tuesday to the PJM Board of Managers.

“Will the Grid of the Future be regionally or locally planned?” they asked. “We believe that the best way to reliably, cost effectively and holistically plan the Grid of the Future is through PJM’s independent regional planning process.”

Signing the letter, in addition to LS Power, were American Municipal Power, Old Dominion Electric Cooperative, the PJM Industrial Customer Coalition and numerous municipal utilities and state public advocates.

The stakeholders noted that the largest component of the spending on supplemental projects in 2018 was that identified by TOs as necessary due to end-of-life (EOL) conditions. “The statistics for 2019 also show that the vast majority of projects were based on claims of EOL conditions and were not subject to regional planning,” they said.

They called for Operating Agreement changes to make clear that PJM plans replacements for facilities identified by TOs as end-of-life, quoting from the PJM Board Reliability Committee’s Oct. 4, 2019 lett e r that said “PJM may be in the best position to determine the more cost-effective regional solution to replace a retired facility.”

“The transmission system in PJM needs to be developed with an eye toward the future, rather than simply rebuilding the grid of the past,” the stakeholders said. “We envision a future where PJM is able to combine drivers of transmission projects, namely public policy projects, with aging infrastructure replacement projects, to plan the Grid of the Future through a robust and transparent regional planning process.”

2019 supplemental project drivers | *PJM*

The stakeholders sent the letter to help the board understand their proposals scheduled for a vote at the May 28 Market and Reliability Committee meeting to change the OA to authorize PJM to direct the most cost-effective solution after the TO provides an EOL notification.

Three EOL proposals were given first reads at the April 30 MRC. The proposals — which would require TOs to share how they make EOL determinations and potentially open at least some replacement projects to competition under the Regional Transmission Expansion Plan (RTEP) — are the result of deliberations over six special MRC meetings since December. (See P J M End-of-life Tx Proposals Near Vote.)

In their letter, the stakeholders insisted their proposal “is consistent with” the Consolidated Transmission Owners Agreement — just one of the many points on which the TOs disagree with the stakeholders. The stakeholders also repeated their assertion that two FERC orders cited by TOs relating to “asset management” are irrelevant to their proposal.

Post contingency local load relief warnings (PCLLRW), wind curtailments and system congestion costs all have trended down in recent years, PJM says. | *PJM*

“Our collective hope is that PJM follows the direction set forth by [CEO Manu] Asthana and refrain from advocating particular policies and instead listens to all stakeholders and perspectives and brings expertise to bear to help achieve the three priorities of reliability, planning and market function for the most efficient delivery of power to [PJM’s] 65 million customers,” they said, inviting “constructive feedback” from the board.

The TOs are likely to make their own case to the board. But at the TEAC meeting, it was left to Alex Stern of Public Service Electric and Gas to get in the last word on their behalf.

“They’re excellent sound bites, but they don’t mesh with the project statistics [PJM] just showed,” Stern said of Segner’s comments.

During his presentation, Berner introduced new graphs showing that post contingency local load relief warnings (PCLLRW), wind curtailments and system congestion costs all have trended down in recent years.

“The data PJM presented in its Project Statistics review today demonstrates that PJM has been a strong regional planner,” Stern added after the meeting. “Particularly in the midst of the current pandemic, the region is worried about a lot of things but, thus far, fortunately, cost effective, reliable power has not been one of them.”

May 13, 2020

ERCOT’s Summer Reserve Margin up to 12.6%

ERCOT said Wednesday it still expects record demand this summer and the potential need for emergency measures, despite a drop in load from the COVID-19 pandemic’s continued effect on the Texas economy.

In making its final resource assessment for the summer months, the grid operator used data from Moody’s Analytics to drop its peak load forecast to 75.2 GW, almost 1.5 GW less than its preliminary assessment. However, the forecast is still higher than last August’s all-time record demand of 74.8 GW.

The pandemic has reduced weekly energy usage within ERCOT’s footprint by 3 to 4%.

“There is a lot of uncertainty in today’s world, but we are confident that Texas will still be hot this summer,” CEO Bill Magness said in a statement.

ERCOT Summer Reserve Margin — ERCOT’s peak load forecast through 2025 | *ERCOT*

Given the expected drop in demand and capacity additions since the last seasonal adequacy resource assessment (SARA), staff adjusted the summer reserve margin to 12.6%, up from 10.6%. Seven wind, solar and storage projects, totaling 276 MW of summer peak contributions, have begun commercial operations since the March SARA.

ERCOT said that even with 82.2 GW of capacity available this summer, energy emergency alerts are still possible should there be extreme weather, low wind generation or higher-than-normal generation outages. The grid operator called two EEAs last summer, when it had a reserve margin of 8.6%. Demand did not reach record peak levels either day, but wind production was unexpectedly low and thermal generation outages were high. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)

Pete Warnken, ERCOT’s manager of resource adequacy, said the risk of an emergency is still present but less likely with a reserve margin that is almost 50% higher. “We anticipate the risk is now lower with typical grid conditions,” he said.

The grid operator also released a preliminary SARA for the fall — 6.8 GW of additional capacity will help meet a predicted peak demand of almost 61 GW — and an updated capacity, demand and reserves (CDR) report.

The CDR report, a 10-year view of the ISO’s reserve capacity, uses pre-COVID load forecasts because of staff’s uncertainty over how the pandemic will affect future years. The report forecasts reserve margins of 17.3% and 19.7% in 2021 and 2022, respectively. ERCOT has approved 2.3 GW of resources for commercial operations since the December 2019 CDR, and staff have also included 6.5 GW of planned resources.

Preliminary data provided by generation project developers indicate the grid operator will have almost 18 GW of planned capacity additions for summer 2021, much of it renewables and some small, flexible gas-fired resources, ERCOT said.