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November 20, 2024

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FERC Terminates MISO Show-cause Order

FERC approved MISO’s reworked ratio for its capacity auctions on Monday, a day before the grid operator began accepting its first offers. It said the RTO’s recalculation ensures it will be “deriving [seasonal accredited capacity] values” consistent with its tariff.

The order also terminated the commission’s show-cause order as it found that MISO satisfactorily recalculated the ratio, which will mean some thermal generators are entering the planning year with lowered capacity accreditation values (EL23-46).

MISO’s Resource Adequacy Subcommittee convened Tuesday, the same day that staff opened the offer window, delayed by FERC’s show-cause order, for its first seasonal planning resource auction. (See MISO Unveils New Seasonal Auction Timeline, Ratio.)

Scott Wright, MISO’s executive director of resource adequacy, said MISO staff is “doing everything [they] can” to carry out the more complicated seasonal auction in a timely fashion. He said he appreciated stakeholders accommodating the dynamic auction schedule. MISO expects to reveal auction clearing prices May 19, about a month later than usual.

MISO’s Durgesh Manjure said that following the auction, MISO stands ready to hear stakeholders’ advice on how to improve it for subsequent years.

“Resource adequacy at MISO is definitely a team sport,” he said.

The auction’s delay hinged on an unforced capacity-to-intermediate seasonal accredited capacity ratio that it uses to determine supply. The ratio helps MISO navigate its new seasonal landscape, converting resources’ seasonal accreditation into unforced capacity terms. The grid operator expresses its planning needs according to unforced capacity values.

The RTO was forced to redo the ratio after a computer error caused some previously exempted planned outages to be counted against some resources’ accreditation values. The grid operator asked FERC that it be allowed to revise individual accreditation values but leave the systemwide ratio alone, as some market participants had already relied on the flawed ratio to enter bilateral capacity arrangements outside of the voluntary auction.

However, FERC ruled that the ratio had to be updated with resources’ latest seasonal accreditation values.

FERC said MISO’s tariff doesn’t afford it “with discretion to decide whether to update the ratio; rather, MISO must calculate the ratio consistent with the formula set forth in the tariff.”

FERC said while it was “sympathetic to arguments” from Vistra and the Electric Power Supply Association (EPSA) that market participants already relied on the erroneous ratio to make supply plans for the planning year, those arguments cannot supersede MISO’s duty to follow rules outlined in its tariff.  

Earlier this month, Vistra and EPSA, a trade group representing competitive suppliers, asked FERC to terminate the proceeding and issue an order to prevent MISO from updating the ratio and lowering resources’ capacity credits. Both said a reworked ratio stands to affect careful supply plans that load-serving entities have buttoned up for weeks based on MISO’s first published capacity values. (See Vistra, EPSA Protest MISO’s Show-cause Order.)

FERC also said the ratio recalculation doesn’t intrude on MISO’s tariff provision requiring LSEs to opt out of the auction and submit a fixed resource adequacy plan before the upcoming a planning year.

Finally, the commission said it disagreed with ESPA’s claim that it was interfering with MISO’s auction.  

“Rather, we are ensuring that the correct values for auction parameters are being used,” FERC said.

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PJM OC Briefs: April 13, 2023

Gas Supply Issues During December Storm Reviewed

PJM presented the Operating Committee a review of the issues that contributed to insufficient natural gas supplies during Winter Storm Elliott, one of the leading causes of generation being offline during the storm.

Gas pipelines took numerous actions in the days leading up to the storm, PJM’s Brian Fitzpatrick said, including restrictions on non-firm contracts and requiring daily balancing of supply and demand. But the actions were insufficient as the storm rolled in and caused force majeure declarations and losses in upstream supply. PJM was aware of the precautionary actions through its daily updates with pipeline operators, however the scale of the production loss was unforeseen, he said.

“We’ve never seen that level of supply loss in the history of Marcellus and Utica,” Fitzpatrick said of the gas producing regions.

One stakeholder said insufficient gas supply is an issue for other RTOs as well, in part because the reliability analyses conducted by pipeline operators are minimal. Pipelines were originally sited to provide fuel for building heating, rather than for delivery to gas-fired generators. With the future of gas uncertain, the stakeholder said, it’s unlikely there will be sufficient investment to simultaneously meet both needs.

Pipeline Operating Conditions (PJM) Content.jpgA PJM graphic shows the alerts and conditions gas pipeline operators supplied the RTO during the December 2022 winter storm. | PJM

Though the majority of generators that experienced outages related to gas fuel supply had non-firm delivery contracts, many generators with firm fuel also experienced interruptions. On Dec. 24, the day with the most outages, generators with non-firm fuel accounted for nearly half of offline capacity by percent of installed capacity (ICAP), while those with firm fuel represented more than a quarter.

Mike Bryson, PJM senior vice president of operations, said PJM generators with all forms of gas supply contracts saw their deliveries curtailed. The RTO is exploring ways of addressing the issue in its critical issue fast path (CIFP) proposal. (See PJM Presents More Detail on CIFP Proposal.)

“This needs to be part of a flexibility attribute going forward,” he said.

Gregory Poulos, executive director of the Consumer Advocates of PJM States (CAPS), questioned whether there will be similar analysis on other major causes of forced outages during Elliott, noting that boiler issues across generation types accounted for more offline capacity than fuel supply for gas generators alone. Fitzpatrick said physical failures constituted around two-thirds of outages and will be the topic of future presentations.

Proposals Seek to Address Transmission Outage Coordination

Stakeholders continued discussion on two proposals to address how PJM and utilities coordinate extended transmission outages. The proposals seek to avoid the surge in congestion pricing caused by line work in Virginia’s Northern Neck peninsula. (See “Transmission Outage Coordination Proposals Discussed,” PJM OC Briefs: March 9, 2023.)

A joint package from PJM, DC Energy and Public Service Enterprise Group (NYSE:PEG) would direct RTO staff to review approved Regional Transmission Expansion Plan (RTEP) projects for any extended outages that may be required and work with the utility to evaluate the impact of any such outages and expand outage information shared by PJM. Upgrades to facilities may be considered if outages are expected to cause significant operational issues.

The Independent Market Monitor’s proposal would aim to identify congestion impacts in advance of projects being approved and request proposals from TOs. It would also treat a request to reschedule an outage as a new request or as a late submission if TOs try to reschedule too far out, seek to reduce or eliminate approval of outage requests after FTR bidding opens and prevent TOs from bypassing rules for long duration outages by breaking them into smaller segments.

Both proposals require that enhanced rating information be consistent with FERC Order 881, which is set to be implemented by July 12, 2025.

Jim Davis, of Dominion Energy (NYSE:D), said the Monitor’s proposal is overly prescriptive and approaches transmission upgrades solely from a markets perspective without taking construction realities into account. Upgrading a large line in one project without segmenting it could create significant impacts on reliability and markets, he said. Other provisions in the Monitor’s proposal would slow the outage process further and increase the risk of projects not being completed on time, he said.

“We as transmission owners need this flexibility because the transmission outage process is dynamic … especially as conditions change in the real time. As for the [Monitor’s] recommendation that PJM not permit transmission owners to segment long duration transmission outages, that’s just not how things work in reality,” Davis said.

 

Other OC Discussions:

  • Stakeholders discussed sunsetting the Synchronous Reserve Deployment Task Force following an August 2022 FERC order rejecting PJM’s Intelligent Reserve Deployment (IRD) proposal. Since the order, the task force has found that the scope of its issue charge and problem statement limit its ability to address the commission’s concerns. PJM’s Vijay Shah stated that there are no proposals currently before the task force.
  • PJM Chief Information Security Officer Steve McElwee encouraged members to ensure their software patches are up to date to avoid falling victim to hackers. He noted that a Canadian utility was attacked on Thursday, with a pro-Russian group claiming responsibility in retaliation for the nation’s backing of Ukraine.
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FERC Approves Termination of FTR Trader’s Member Status

FERC on Friday granted PJM’s request to terminate the membership of Hill Energy Resource & Services following the company’s failure to pay several invoices for financial transmission rights transactions on time in 2022 (ER23-423).

PJM declared Hill to be in default on its credit obligations three times in January 2022 totaling more than $18 million, as well as being in default on five payments between January and February totaling $4,301,233.96, according to the RTO’s filings.

The company argued that PJM’s approval of the Lanexa-Dunnsville transmission line into Virginia’s Northern Neck peninsula led to volatile pricing in the region, compounded by tariff violations that Hill alleged PJM committed by issuing collateral calls and subsequently preventing the company from liquidating FTR positions. (See PJM Weighs Options on Hill Energy FTR Default.)

“Essentially, PJM took actions that resulted in abnormal market conditions, those actions led to unjust and unreasonable rates, and PJM now asserts that Hill Energy’s failure to post collateral for the unjust and unreasonable rates is a legitimate basis upon which to terminate Hill Energy’s membership,” Hill stated in its protest. The company did not provide comment on the order Monday.

After work began on the Lanexa-Dunnsville line in January 2022, Hill said prices began fluctuating between the energy offers of the limited number of combustion turbines sited on the peninsula and the $2,000/MWh transmission constraint penalty factor (TCPF), leading to “substantial losses leading to payment defaults that otherwise would not have occurred.” It argued that given the unique circumstances — which led to a separate PJM stakeholder process and FERC filing to permit the RTO to temporarily suspend the TCPF in the region — a permanent termination of the company’s membership was not warranted. (See FERC Approves Pause of PJM Tx Constraint Penalty Factor in Va.)

“Absent the application of the TCPF and the resultant unjust and unreasonable rates, Hill Energy believes it would have had positive returns or much smaller and manageable losses, and defaults likely would not have occurred,” Hill’s filings say.

The protest also argued that that PJM’s first $921,500 collateral call on Jan. 11, 2022, constituted a tariff violation, citing section VI.C.7, which states that the RTO could only declare a credit default after a market participant failed “to satisfy a request for collateral for two consecutive auctions of overlapping periods, e.g., two balance of planning period auctions, an annual FTR auction and a balance of planning period auction, or two long-term FTR auctions.”

The collateral call created a “cascading effect” once the company did not supply the additional funds by leading PJM to revoke the company’s ability to sell open FTR positions and prevent it from accessing market data to continue mitigating its obligations. The company stated that by liquidating open positions, it aimed to reduce its collateral requirement under section VI.C.7, but that action was not immediately taken by PJM after the company made its request. The third collateral call on Jan. 13 for $17 million “crippled” the company’s operations, as it believed it was required to first pay its collateral before addressing invoices.

“The timely sale or liquidation of these positions would have reduced its collateral requirement, thereby allowing Hill Energy to pay its January and February 2022 invoices on time, avoiding any payment defaults,” the company said.

Responding to the protest, PJM stated that section VI.C.7 is limited to particular FTR auctions, rather than general credit defaults and is not applicable to Hill’s circumstances. It described the issues raised by the company as “attempts to confuse the issues and raise disputes that do not stay PJM’s obligation to terminate Hill Energy’s membership.”

PJM also said that any appeals to a membership termination must be done through its dispute resolution process, although the initiation of an appeal does not stay the ability to seek termination. Though Hill added an alternative request to its protest asking for the commission to consider instead approving a suspension of its membership while it engaged in that process, the order did not address the request.

In approving the request to terminate Hill’s membership, FERC focused on the five invoices the company failed to pay between Jan. 25 and Feb. 23, finding that the company did not provide any tariff provisions supporting its case for excusing its nonpayment. Provided that is reason enough for termination, the commission said it does not need to address whether PJM followed its tariff in issuing the collateral calls. Responding to the company’s argument that it would have been able to use revenues from its sell-only FTR bids to pay its invoices if PJM had submitted them when originally requested, the commission said it found that to be “speculative and uncompelling.”

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NERC Says Changes Coming to Physical Security Standards

NERC told FERC in a report Friday that it will soon begin a new standards development project to examine changes to reliability standard CIP-014-3 (Physical security) in response to the ongoing threat of physical violence against grid assets.

FERC ordered the report at its December open meeting citing recent physical security incidents, primarily the Dec. 3 gunfire attack on two Duke Energy (NYSE:DUK) substations in North Carolina, which left 45,000 customers without power for as long as four days (RD23-2). (See FERC Orders NERC Review on Physical Security.)

Physical security has remained a pressing concern since then because of subsequent sabotage events in Seattle and Las Vegas, as well as the arrest of a neo-Nazi leader for plotting to attack electric substations in Baltimore. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.) NERC CEO Jim Robb said in a statement that the “heightened physical security threat environment and the high-profile attacks … in the fourth quarter of 2022” made the new report a priority for the ERO Enterprise.

“Our study outlines actions to strengthen the physical security standard and foster robust stakeholder engagement to consider additional risk-based enhancements,” Robb said. “The actions outlined in our report will help further secure critical bulk power system assets and ensure the foundational protections of CIP-014 are keeping pace with a dynamic risk environment.”

Standard Modifications Planned

CIP-014-3 was approved by FERC last year with the purpose of identifying and protecting transmission stations and substations that, if damaged in a physical attack, “could result in instability, uncontrolled separation, or cascading within an interconnection.” It requires transmission owners to perform periodic risk assessments of their transmission facilities and control centers to determine which of them are critical to reliability, evaluate their potential physical security threats and vulnerabilities, and develop a security plan to address those threats.

The commission wanted NERC to assess the effectiveness of CIP-014-3 in light of the North Carolina attacks. FERC ordered the ERO to evaluate the adequacy of the standard’s applicability criteria, the adequacy of the required risk assessment, and whether a minimum level of protection should be required for all substations on the North American grid.

In the report, NERC said that the criteria are still appropriate to “focus limited industry resources” on the most critical grid facilities, and that its evidence suggested that expanding the criteria would not identify any additional critical substations. As a result, the ERO recommended against expanding the criteria.

However, the ERO also acknowledged that “supplemental data” such as “expansion plans, future year realized conditions, impacts of grid transformation, and other similar projections that alter year-to-year … could alter substation configuration” and bring currently unqualified facilities under the jurisdiction of the standard. NERC plans to hold a technical conference with FERC to identify the type of substation configurations to be studied, and to establish data needs for conducting those studies; the conference has not been scheduled.

NERC did find that the standard’s language requiring TOs to study the effect of losing a substation needs “additional clarification as [to] how registered entities must conduct the assessments.” The report said that utilities’ approaches to the studies are inconsistent in both their methods and their frequency. Although this can occur because they lack in-house subject matter experts, the root cause is “a lack of specificity in the requirement language,” NERC said.

The ERO said it will begin a new project to examine the issue and determine how the standard could be modified to provide more clarity. Suggested objectives of the project include clarifying the methods for studying instability, uncontrolled separation, and cascading; clarifying the documentation and usage of criteria to identify instability, uncontrolled separation, or cascading; and clarifying the risk assessment to account for adjacent substations of differing ownership.

Conference to Address Minimum Security Requirements

Finally, in response to FERC’s question about requiring that protection be implemented on all grid facilities, NERC suggested that a “more holistic approach [would] provide greater long-term flexibility and minimize the impacts of physical attacks on [grid] reliability.” The ERO acknowledged that a uniform set of protections might prevent some physical damage but warned that it would not “guarantee the protections will safeguard against more sophisticated or coordinated attacks.”

However, NERC also suggested a second technical conference to evaluate “the appropriate combination of reliability, resiliency and security measures that would be effective in helping to mitigate the impact of physical security attacks.” Topics covered by the conference will include:

  • the appropriate approach to identifying the objective of a minimum level of protections, risks to be mitigated and industry resources necessary to meet minimum requirements;
  • expanding the use of planning studies to evaluate physical security attacks and develop corrective action plans to deal with inadequate performance;
  • enhancing operational planning assessments to include loss of assets from physical attacks; and
  • enhancing transmission planning and TO requirements to ensure spare equipment pools are appropriate to respond to security incidents.

NERC will use the technical conference as a basis for determining its future moves, including additional changes to its reliability standards. The conference, like the one dedicated to the applicability criteria, has not been scheduled.

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Calif. Agency Seeks to Transform Wildfire Safety Culture

INCLINE VILLAGE, Nev. – A relatively new California agency is working to transform utilities’ wildfire safety culture by shifting away from penalties and enforcement to a proactive, learning-based approach.

The California Office of Energy Infrastructure Safety was established through state legislation following devastating wildfires in 2017 and 2018, according to Caroline Thomas Jacobs, the office’s director. The agency got its start as the Wildfire Safety Division within the California Public Utilities Commission but became a standalone department in July 2021.

The office, known as Energy Safety for short, is now about three years old.

Thomas Jacobs talked about the new initiative during a panel discussion at last week’s joint meeting of the Committee on Regional Electric Power Cooperation (CREPC) and the Western Interconnection Regional Advisory Body (WIRAB).

Energy Safety’s activities are based on a shift from “a compliance-based, reactive, penalty-enforcement approach to issues of safety to implementing a new, proactive planning-learning-improvement regulatory cycle,” Thomas Jacobs said.

Among its duties, the agency reviews utilities’ wildfire mitigation plans and assesses their safety culture each year. Wildfire mitigation plans are based on a “maturity model” in which utilities explain where they are in terms of wildfire prevention activities and where they expect to be as a result of safety investments.

In the safety culture assessment, utilities survey their employees and contractors — from frontline inspectors to senior managers — on their understanding of and approach to wildfire safety. Energy Safety then makes recommendations on how safety culture could be improved and follows up to see if the recommendations are being implemented.

But enforcement isn’t disregarded: Energy Safety also conducts inspections, audits and investigations to see whether utilities are complying with their approved wildfire mitigation plans.

Panelist Brian D’Agostino, vice president of wildfire and climate science at San Diego Gas & Electric, said the new framework is “having a real impact” on the utility’s culture and helping it maintain focus on priority safety areas.

“These safety culture assessments don’t come back and say everything’s great top-to-bottom,” D’Agostino said. “It gives us areas where we can really focus on and areas where we can improve.”

Panelist Sumeet Singh talked about how safety culture has changed at Pacific Gas and Electric, where he is executive vice president of operations and chief operating officer.

“Frankly, the wildfire risk is something that surprised PG&E,” Singh said. “One of the big reasons for the surprise was the significant drought that happened in 2014 to 2016 that completely changed the environment in which the overhead electric assets operated.”

The change was initially missed because of the utility’s focus on reliability and running assets to failure, Singh said. Now, he said, PG&E has adopted a mindset seen in high-hazard industries.

The Camp Fire, which destroyed much of the town of Paradise in November 2018 and killed more than 80 people, along with a series of Northern California wine country fires in October 2017, forced PG&E into bankruptcy and led to a multibillion-dollar settlement with fire victims.

In June 2020, the utility pleaded guilty to 84 counts of involuntary manslaughter and one count of arson in connection with the Camp Fire. In February, PG&E pleaded not guilty to 11 charges stemming from the September 2020 Zogg Fire. (See PG&E Pleads Not Guilty to Manslaughter Charges.)

Singh said that mitigations in the utility’s wildfire safety plan include plans for undergrounding 10,000 miles of distribution lines and replacing bare lines with covered conductor or insulated wire in high fire-threat areas. (See PG&E Scales Back Plan to Underground Lines.) PG&E is also turning to remote grids and microgrids in situations where a handful of customers in remote areas are served by distribution lines that run across risky terrain.

But Singh said PG&E is also working to change its safety culture. One goal is to make sure that employees who know the assets feel empowered to speak up if they spot a problem, he said.

Another issue has been the different perception of risk among employees ranging from inspectors to supervisors and executive leadership. The focus now is to “align on the perception of risk,” Singh said.

He gave as an example an employee who has been working on electric systems for a long time.

“They may have been OK at one point in time to look at [an] adverse condition in the health of a tree and say, you know what, we can actually remove or address that in six months,” Singh said. “That’s not the case anymore. That’s an immediate safety issue that actually needs to be addressed right away.”

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House Hearing Examines State of the Nuclear Power Industry

House lawmakers heard from nuclear industry experts Tuesday as they get started on legislation aimed at helping the deployment of advanced reactors across the U.S.

“To expand the industry, it is vital we encourage regulatory certainty and make sure our reactor licensing processes enable the safe and broad deployment of nuclear technologies,” said Rep. Jeff Duncan (R-S.C.), chair of the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security. “This is especially important for advanced reactor technologies.”

Nuclear power now provides about 20% of the country’s electricity, including about half of its carbon-free energy, and it can help eliminate emissions on the grid, said the subcommittee’s ranking member, Rep. Diana DeGette (D-Colo.). But several things need to happen for nuclear to remain a key part of the generation mix going forward, she said.

“The United States must develop a comprehensive science-based strategy to dispose of spent fuel — a strategy that does not cause harm to public health or our environment,” said DeGette. “If we don’t have a long-term permanent solution for disposing of nuclear waste, then we will struggle to be able to use this source of carbon-free electricity.”

She said the other key challenge is figuring out what do with the existing fleet, which has seen some scattered retirements in recent years, but only one new nuclear plant coming online: Southern Co.’s Vogtle plant.

Once Vogtle’s units are online, the country will have 94 reactors operating, and it will be important to extend their operating lives while securing them a more stable source of uranium, said Idaho National Laboratory’s Jess Gehin.

“Currently, our nation imports 90% of our uranium needed for our reactor fleet,” Gehin said. “This includes imports from Russia; eliminating these imports from Russia requires us to establish an expanded uranium-enrichment capability domestically and with our close allies.”

Some of the proposed new reactors such as TerraPower’s natrium reactor in Wyoming and X-energy’s Xe-100 planned for deployment at a Dow Chemical facility on the Gulf Coast need a stable, domestic supply of high-assay, low-enrichment uranium that is not produced here at all, said Gehin.

Duke Energy (NYSE:DUK) has the largest fleet of 11 “regulated” nuclear units at its vertically integrated utilities in the Carolinas, and the North Carolina Utilities Commission has approved its early investment to consider building new, advanced reactors, said Regis Repko, the company’s senior vice president of generation and transmission strategy.

“We plan to add unprecedented numbers … of solar energy, storage [and] wind power to the grid as we continue to retire our aging coal fleet,” Repko said. “However, we must have firm, dispatchable resources, such as nuclear and natural gas, to support renewable energy resources. Our customers depend on us, and we must not jeopardize reliability or affordability in this transition.”

Duke’s 11 plants are all set to retire between 2030 and 2046. To avoid losing those plants, which produce half the energy and 80% of the clean energy for its utilities in the Carolinas, the company would like to extend their licenses another 20 years. Duke also plans to build 8 GW of new nuclear power.

The firm plans to work with stakeholders and the Nuclear Regulatory Commission to ensure the licensing process for those new reactors is effective, efficient and in line with the safety of the new reactor designs, Repko said.

The bipartisan support seen at the hearing, recent advances in Europe and California’s decision to extend the life of the Diablo Canyon nuclear plant all point to the increased support the technology has seen in recent years, said Clean Air Task Force Executive Director Armond Cohen.

“The problem is that we’re just not moving at any scale and pace that’s relevant to climate. To be relevant to climate, nuclear is going to have to be churning out something like 100 GW/year globally,” said Cohen. “That’s about in the range of where we were with coal and gas in a sustained way for a few years. We have to be really running at that scale. We’re about 10 GW/year, so, we need to be 10 times where we are.”

To have an impact on global climate change, the U.S. nuclear industry will need to export its technology because domestic emissions only amount to 15% of global emissions, he added.

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NYISO Seeking to Increase Emissions Transparency

NYISO on Monday presented the Installed Capacity Working Group/Market Issues Working Group (ICAP/MIWG) with proposed methodology for measuring implied marginal emission rates (IMERs) to increase transparency around New York’s emissions output by providing real-time data.

The ISO chose the IMER “heat rate” methodology to measure emissions production over other options because, staff said, it is highly variable and granular, performs well in grids with clearly defined marginal fuel types, and helps identify persistent congestion patterns.

The methodology uses LMPs, fuel prices, emissions costs, and variable operation and maintenance costs as inputs to estimate the implied heat rate, which is then used to estimate the real-time zonal IMER in tons of carbon per megawatt-hour for a given implied marginal fuel.

Stakeholders requested NYISO publish real time marginal and average zonal emissions rates data to help them comply with state energy and climate legislation, particularly Local Law 97, which set strict carbon reduction standards for large New York City buildings. (See NYC Proposes Rules to Implement Building Emissions Law.)

Aaron Breidenbaugh, director of regulatory affairs at CPower Energy Management, asked why stakeholders had requested this project, to which William Acker, executive director of the New York Battery and Energy Storage Technology Consortium, responded that his organization, along with state agencies and other stakeholders, need this information to support LL97 compliance.

“We need to have at least hourly marginal numbers available for the accounting under [LL97], and secondly, it’s valuable to have something that is forward looking and that isn’t simply scorekeeping but is actually actionable by people managing buildings in New York City,” Acker said.

NYISO will return to the ICAP/MIWG either next month or in June to share additional information on the methodology’s inputs and is targeting the fourth quarter to deliver the functional requirement specifications.

Renewable Regulation Requirements

NYISO also presented the ICAP/MIWG with proposed revisions to the regulation requirements for renewable resources in the state.

As New York installs more wind and solar projects, the ISO has been required to regularly update its regulation requirements, starting in 2010 and again in 2016, to ensure that these resources are not negatively impacting its ability to balance the bulk power system or disrupting voltage requirements.

NYISO modeled two scenarios that predict the total amount of installed nameplate capacities of land-based wind (LBW), offshore wind (OSW) and solar at the end of a given year: Scenario 1 projects that 3,000 MW of LBW, 125 MW of OSW and 7,651 MW of solar will be installed by 2024; while Scenario 2 projects 3,700 MW, 125 MW and 9,768 MW, respectively, will be installed by 2026.

NYISO is proposing that Scenario 1’s set of new regulation requirements be implemented on June 1, and that Scenario 2 be implemented in 2025. The ISO would send stakeholders market notices in case capacity levels approach those in the scenarios earlier than projected.

NYISO will seek approval for its proposed scenarios and their implementation timelines at the Operating Committee’s meeting Thursday.

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Inslee Approves 160 MW of Solar in Central Wash.

YAKIMA, Wash. — Washington Gov. Jay Inslee on Monday said he has approved plans by Cypress Creek Renewables to construct two large solar farms in Yakima County in the central part of the state.

Cypress Creek will build the two 80-MW projects — High Top Solar and Ostra Solar — just west of the border between Yakima and Benton counties. The remote area is home to a just a handful of farms and 20 miles from the nearest town of Sunnyside. The two farms are expected to provide enough energy to power roughly 30,000 homes in the region.

Sarah Slusser 2023-04-17 (RTO Insider LLC) FI.jpgSarah Slusser, Cypress Creek Renewables | © RTO Insider LLC

Speaking at a press conference in the city of Yakima, Inslee noted that no farmland will be displaced by the projects. “Our team took great care to micro-site each project,” Cypress Creek CEO Sarah Slusser added.

The two solar farms are expected to go online in 2025 and 2026, according to Tai Wallace, senior director of development at Cypress Creek. Wallace declined to provide a budget for construction, which is expected to create about 300 to 550 jobs, with about five to 10 remaining once the projects are completed.

Inslee has been leading to push to set up numerous wind and solar farms in Washington to wean the state from electricity produced by fossil fuels. His administration has calculated that the state will need to double its electricity production by 2050 to replace fossil fuel resources while accommodating an increasing population.

“We are the perfect place to lead the world in clean energy,” Inslee said. 

When questioned on whether he would uncritically approve wind and solar projects because of his strong support for alternative energy sources, Inslee replied: “We don’t rubber-stamp these things. We look at them with a critical eye.” 

Washington law allows energy project developers to pick whether they want the state government or the appropriate county government to review their permit applications. Many applicants choose the state approach of going through the Washington Energy Facilities Siting Evaluation Council, which makes recommendations to the governor on whether to approve a project.

High Top and Ostra join two other eastern Yakima County solar farms set for construction. They include the 80-MW Goose Prairie project, approved by Inslee in December 2021, and the 94-MW Black Rock project, approved by Yakima County officials in May 2022. 

The Black Rock project will share space with sheep that graze on the grass on the site, making it the second agrivoltaic site in Washington. The first such project mingling solar with farming is already online on the Colville Indian Reservation north of the Grand Coulee Dam. 

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NJ To Accelerate RGGI Fund Expenditures

New Jersey has been slow to spend Regional Greenhouse Gas Initiative (RGGI) funds since returning to the program, but it is taking steps to accelerate the process, state officials said last week as they solicited public input on how to use the money over the next three years.

Speaking Tuesday at the second of four public hearings into future priorities for RGGI funds, Paul Baldauf, assistant commissioner for air, energy and materials sustainability at the state’s Department of Environmental Protection, said “there’s a lot of lessons learned” in the state’s handling of the $372 million allocated to the state over the past three years.

Baldauf spoke nearly two weeks after the state announced the expenditure of $70 million — about 30% of the funds expended so far, mostly on electric school buses and other battery-powered heavy-duty vehicles. The state still must spend about $100 million of the RGGI funds allocated in the three-year period. State officials said they expect the funding plan, with public comments incorporated, will be released in the next two months, by which time more RGGI funds should be available and investment in projects will begin.

“We’re going to make a commitment in the second three-year period to, quite honestly, do a little better job on our end,” Baldauf said, referring to the need to spend the funds sooner.

“We want that money flow to be constant so we can see the results out in the street versus the money sitting in an account somewhere,” he said. “We’ve changed a lot of internal processes along the way to help with that, but we still have steps to go … So it’s really more seamless than anything else, and as the money comes in every quarter, that money [should go] out every quarter with the right things.”

He added that the state will continue the strategy of “almost solely” focusing spending on environmental justice communities.

Shifting Perspectives

Yet the hearings showed clear potential for shifting the state’s priorities elsewhere, depending on public response. Although a founding member of RGGI in 2005, New Jersey left the program in 2012 at the direction of then-Gov. Chris Christie (R), then reentered in 2020 under current Gov. Phil Murphy (D).

While the first three years’ worth of funds were allocated to transportation, the state’s largest source of emissions at 37%, the state is looking to broaden that focus, officials said. (See NJ Allocates $70M in RGGI Funds for Heavy-duty EVs.)

Some of the funding will shift to building electrification, one of the “primary areas” for which the state’s Board of Public Utilities is seeking input, BPU Chief of Staff Taryn Boland said.

One reason is that 73% of New Jersey homes are heated by natural gas, with another 10% heated with delivered fuels such as heating oil and propane — about 30% higher than the national average, Boland said. Meanwhile, just 16% of the state’s residence are heated by electricity, compared with a national average of 41%, she said.

“As the country is beginning to shift to electric air and water heating, it’s important to know that New Jersey is also way behind in the pack,” she said. “We know that building electrification will lead to cost savings and yield beneficial health outcomes. We know strategically and equitably designed programs to help drive … this transition is critical.”

That perspective, embraced by Gov. Murphy, has proven controversial in the past. The DEP in December dropped a plan to prohibit the installation of fossil fuel-fired commercial boilers amid vigorous opposition from business groups, who say electric boilers are vastly more expensive to install. (See NJ Backs off Ban on Commercial-size Fossil Fuel Boilers.)  But Murphy in February signed executive orders establishing a goal to install electric heating and cooling equipment in 400,000 homes and 20,000 commercial properties by 2030.

Speaking after the Newark meeting, Boland said the state has not determined the priorities, but that building electrification is one competing priority among several. The state’s RGGI spending is divided among the BPU and DEP, each of which is allocated 20%, and the Economic Development Authority (EDA), which spends 60% of the funds. State officials said part of their effort to accelerate the spending has been to smooth the coordination and decision making among the three agencies.

Together they have crafted five main priorities for guiding RGGI investments: to strengthen the grid and promote “healthy homes”; stimulate “clean and equitable” transportation; “strengthen” the state’s forests; promote carbon capture in coastal areas; and reduce the use of “high warming refrigerants.”

Improving Efficiency

The BPU also thinks the state should put greater emphasis on the agency’s pilot “whole house” program, in which properties in low-income areas of the state capital, Trenton, are evaluated for health and safety hazards and efficiency, and remediated where necessary, Boland said.

“We’re looking to utilize funding in this strategic round to really bring that program to scale statewide,” she said. “We’re looking to build a strong portfolio of electrification and energy efficiency programs that leverage the federal incentives that are now available and drive down the cost of building [decarbonization] efforts.”

Peg Hanna, DEP assistant director of air monitoring and mobile sources, said the agency wants to continue investing RGGI money on EV projects, such as fleets of electric municipal school buses and garbage trucks, and to help put EV chargers in multi-unit dwellings, where residents have difficulty installing their own chargers. (See NJ RGGI Spending Focuses on Transportation.)

“We also know that the statistics show a lot of our ride hailing drivers live in multi-unit dwellings,” she said. “So providing charging hubs for those residents will also enable ride hailing to become electric.”

In a similar vein, the DEP is looking to pursue more programs such as the Go Trenton pilot program, still under development. The pilot will use RGGI funds to address the likelihood that EVs will struggle to take hold in the city because of low incomes and the fact that 30% of households don’t have a car, while 21% of residents report using car-sharing to get to work. Go Trenton would provide EV options such as a car-sharing, ridesharing and shuttle services.

During last week’s hearing, an audience member questioned whether RGGI funds could be used to help residents in environmental justice areas who can’t afford to buy an EV to repair their internal combustion engine vehicle.

Hanna said the issue clearly needs to be addressed, given that the state won’t replace all of its 6 million ICE vehicles in the near future but needs to minimize emissions from those cars.

“Making sure that the existing fleet is well-maintained is a core focus of our statewide inspection and maintenance program,” she said. “Are there ways to identify high emitters and to make sure the vehicles are repaired more quickly? Sure. We would need our friends at motor vehicle commission to be in on that discussion with us. But that’s something that we have looked at in the past — doing things like remote sensing in high traffic corridors to try to identify the highest emitters and get them pulled in for an inspection.”

The state also is working on adopting California vehicle rules to “ratchet down on the emissions from new internal combustion engines that can be sold and registered in the state,” she said.

Combating Super Pollutants 

The third hearing on Thursday focused on “buildings, [the] grid and refrigerants,” highlighting potential projects that weren’t funded by RGGI money in the first phase.

For the EDA, key candidates for RGGI expenditures include improving grid resiliency to reduce electrical outages in overburdened communities and financing for “beneficial electrification, renewable energy distributed energy resources or energy efficiency projects in commercial buildings,” said Marta Cabral, senior project officer for clean energy programs at the EDA. The money could also be used to finance improvements that reduce emissions from commercial and industrial buildings, she said.

A DEP official said RGGI funds could additionally be used to reduce the use of refrigerants in low-income communities.

Hydrofluorocarbons account for 6% of the state’s greenhouse gas emissions and are “considered a climate super pollutant,” said Ky Asral, bureau chief of the DEP’s Bureau of Sustainability. That means that any reduction in their use would have a big impact, but businesses in low-income areas may balk at installing more expensive ultra-low commercial refrigeration system chillers, he said, suggesting that incentives funded by the RGGI program could get the job done.

“Funding the incremental cost from the installation of new refrigeration systems to ultra-low systems will accelerate the adoption of these systems and have immediate impact on reducing the global warming pollutants from this sector,” he said. “Creating similar incentives in overburdened communities for retrofitting or replacing high [global warming potential] refrigeration systems or chillers will keep much needed commercial facilities like supermarkets in neighborhoods that may otherwise not be able to afford the transition on their own.”

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PJM MIC Briefs: April. 12, 2023

Stakeholders Endorse Manual Revisions for Real-time Values

VALLEY FORGE, Pa. — The PJM Market Implementation Committee overwhelmingly voted to endorse manual revisions to put limits on when generators can submit real-time values.

The revisions would only permit real-time values to be used for physical unit limitations or circumstances outside the generation owner’s control. Documentation of those factors would be required to be submitted to PJM and the Independent Market Monitor within three days. If real-time values are improperly submitted, PJM’s Lauren Strella Wahba said the RTO would have the ability to reject them after the fact and the option to refer the seller to FERC.

Real-time values are meant to be a temporary way for generators to provide PJM its operating capabilities when it cannot satisfy its unit-specific parameter limits or approved parameter-limited exceptions. The RTO has found that the values have been used to override parameter limits or exceptions in some instances, Wahba told the MIC, while in other circumstances dispatchers would only become aware of a deviation from operating parameters when they called upon a unit.

FERC rejected a previous proposal to codify real-time values in the tariff, stating in a May 2021 order that submissions would not have been based on actual physical or operational constraints. The commission also stated that PJM’s status quo governing documents could contain market power issues (EL21-78).

Several stakeholders questioned why PJM sought endorsement of new manual language rather than embarking directly on making tariff revisions. PJM’s Chen Lu said real-time values currently exist in the manuals without a requirement for physical constraints and by making manual revisions now, the changes can be implemented while stakeholders work toward a FERC filing on tariff revisions.

Quick Fix Proposed to Address Falling Synch Reserve Deployment Response Rate

PJM proposed initiating a quick-fix process to address synchronized reserve deployment times exceeding PJM’s 10-minute internal standard since it implemented an overhaul of the reserve market on Oct. 1, 2022. Nonperformance rates have also increased to around 49% during the eight reserve deployments since the implementation, excluding those during the December 2022 winter storm.

The quick-fix process allows for a problem statement and issue charge to be endorsed concurrently with a proposed solution. Under the proposed manual revisions, PJM would be able to extend the second step of the operating reserve demand curve (ORDC) process by taking nonperforming reserve resources into account, allow the addition of on- and off-peak periods, and require that the extended values be posted as they’re changed.

PJM’s Phil D’Antonio said the RTO believes that the issue lies in market participant training, rather than in the pricing of reserves, and ongoing outreach to generators will yield progress. Glen Boyle, also of PJM, said that because penalties are based on synchronized reserve revenues earned and clearing prices are low, penalties are also low at this time.

Monitor Joe Bowring said he believes the issue is not appropriate for a quick-fix solution, as there is no demonstrated reliability issue that would be addressed by the proposed change.

He noted that PJM’s proposal would nearly quintuple the second step of the ORDC, from 190 MW to 890 MW, without any quantitative support for that significant a change, which he argued would trigger shortage prices more often and increase the price of synchronized reserves. Bowring also pointed out that the Oct. 1, 2022, change in the reserve market design increased the supply of synchronized reserves and included a must-offer requirement. He argued reserve prices since Oct. 1 have not been too low but have appropriately reflected the balance of supply and demand.

Under the applicable NERC standards, only one spinning event has exceeded the limit, and that is under investigation, Bowring said. He agreed with PJM that individual unit response times have been a problem and that both the Monitor and PJM are contacting individual unit owners to investigate the reasons for the poor performance. Bowring also stated that PJM’s rules for not paying resource owners for nonperformance were too weak and contributed to the performance issues.

Stakeholders Fine-tune Design Components on Local Considerations for Net CONE

Stakeholders continued the identification of design components to include in the drafting of proposals on whether and how to include regional factors impacting the net cost of new entry (CONE), such as environmental regulations or taxes. The MIC also discussed interests and design components during the February and March meetings, with the next phase being the creation of packages. (See “Discussion on Local Considerations for Net CONE,” PJM MIC Briefs: March 8, 2023.)

James Wilson, a consultant for five state consumer advocates, recommended two design components: a transition mechanism when net CONE is updated, potentially capping any increase at 20% during years between Quadrennial Reviews; and consideration of changes to the variable resource requirement (VRR) capacity demand curve shape — the latter of which he acknowledged had previously been ruled out of scope, which he suggested could ultimately result in any proposal to just change net CONE rules being rejected by FERC.

Stakeholders discussed whether CONE values and the reference resource should be reviewed whenever an impact, particularly signed legislation, is identified, including in between Quadrennial Reviews.

The discussion also looked at whether the creation of a new CONE area should result in the original region parameters being recalculated to account for the different footprint, particularly if the reference resource was based in the excised area.

Discussion on Co-located Load Packages

Several proposals to define how configurations in which load is directly connected to generators fit into PJM’s rules continued to be discussed by stakeholders.

Much of the discussion was centered on whether generators co-located with load that does not have a direct interconnection to the transmission grid should be required to relinquish a portion of their capacity interconnection rights (CIRs) equal to the energy consumed by the load, as they currently are, or if they should be permitted to retain that capacity, as well as whether interconnection and ancillary services charges should be assessed. (See “Proposals on Rules for Generation with Co-located Load Presented,” PJM MIC Briefs: March 8, 2023.)

Exelon’s Sharon Midgley said the company’s proposal would allow generators to retain their CIRs, but the facility would be classified as a load-serving entity for the co-located load and all applicable LSE charges and credits would be applied to it. She noted the package currently only focuses on capacity resources, but it will be expanded in the future to consider energy-only generation, given the interest expressed by other PJM members as well.

“Our primary interest is having more clarity in PJM’s rules,” she said.

A proposal from the Advanced Energy Management Alliance would codify all status quo rules and practices, with the addition of creating penalties for the host generator if the co-located load is not curtailed when the generator is dispatched.

Two proposals from the Monitor and a joint package from Constellation Energy and Brookfield Renewable remain largely unchanged since the MIC showed less than 20% support in a November poll. Following the poll, Bowring — whose package largely codifies existing practices and adds administrative requirements and charges — suggested discontinuing the discussion, but stakeholders felt that clarified rules are needed.

The Constellation-Brookfield proposal would allow generators to retain their full CIRs without making either the generation or the load subject to ancillary service charges, under the argument that the load does not benefit from grid services. Former Constellation Director of Wholesale Market Development Jason Barker stated that the arrangement the company envisioned under the rules would be a nuclear facility supplying power for highly interruptible load, such as hydrogen electrolyzers. (See “Limited Support for Co-located Load Proposals,” PJM MIC Briefs: Dec. 7, 2022.)

Bowring argued that PJM should be required to assess the impact of diverting a significant amount of low-cost energy off the grid to meet new load added to the grid behind the generators. He also said that emissions would increase as a result because nuclear energy would be dedicated to the new loads while existing load would be met by the emitting resources at the top of the supply stack. A related result would be an increase in energy market prices that the Monitor had previously estimated as exceeding a billion dollars, Bowring said.

“Nuclear plants were never built to provide energy for a few hours per year. The promise to provide energy from the resources for a few peak hours a year is not consistent with the obligation of capacity resources.”

First Read on Smooth Supply Curve Quick Fix

PJM presented a proposal to initiate a quick fix process to clarify that the informational smoothed supply curves PJM publishes after Base Residual Auctions will not be created for Incremental Auctions (IAs). PJM’s Skyler Marzewski told the committee that PJM cannot create smoothed supply curves for IAs because of the lack of demand curves in those auctions and the risk that they could be used to expose market sensitive data.