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November 5, 2024

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PJM Updates Proposal as CIFP Nears End

PJM presented several changes to its Critical Issue Fast Path (CIFP) proposal during the process’ meeting Thursday, reworking portions related to the seasonal market, weatherization, site visits, performance assessments and market power mitigation.

Getting through a portion of PJM’s 79-slide presentation spanned the entirety of the meeting, postponing presentations from Constellation Energy and the Independent Market Monitor to the next CIFP meeting Tuesday. Additional sections of PJM’s presentation pertaining to reliability risk modeling and accreditation were moved to Tuesday’s meeting, which is set to include presentations from Vistra, Buckeye Power and Leeward Renewable Energy. (See PJM Updates Risk Analysis; Stakeholders Present Revised CIFP Proposals.)

Following Tuesday’s meeting, only one Stage 3 meeting remains on the calendar, set for Aug. 7. The following week will be saturated with standing committee meetings, with Aug. 13 being the final day for agenda items and documents to be added to the materials for the Stage 4 meeting on Aug. 23. In that meeting, stakeholders will present to the PJM Board of Managers and subsequent Members Committee meeting, which will include the vote to recommend a package to the board.

The Stage 4 meeting will begin with a detailed presentation of PJM’s proposal, after which only members and invited non-member stakeholders will be allowed to continue participating. A sign-up form will be emailed to stakeholders subscribed to the CIFP and MC mailing lists.

Seasonal Auction Design Shifts to MRI Curves over VRR

PJM Vice President of Market Design Adam Keech said the new seasonal design stemmed from stakeholder concerns that PJM’s proposal was overly complex and not transparent. The previous iteration would have created variable resource requirement (VRR) curves for each season and aligned the price with the point on the annual VRR curve corresponding to the amount of cleared capacity. (See PJM Adds Seasonal Capacity to Stage 3 of CIFP Proposal.)

Thursday’s proposal instead would use marginal reliability impact (MRI) curves for the seasonal auctions, which would be set in advance and with no adjustments made during the auction clearing. The shape of the MRI curves generally would align with the status quo VRR slope, but the “amplitude” of the curve would be increased to ensure resources could retain the annual costs of taking on a capacity commitment in a single season in the event the other season cleared at zero.

The MRI curve for each season would be calibrated so that if the amount of capacity procured was at or lower than the reliability requirement, the corresponding price would be at least the annual net cost of new entry (CONE) for the reference resource.

PJM Director of Economics Walter Graf compared the current approach to how locational deliverability areas (LDAs) have their own VRR curves designed to ensure that the reference resource can meet its reliability requirement assuming the rest of the RTO cleared at $0 and no outside revenues would be available for resources within the LDA.

Several stakeholders expressed concern that increasing the amplitude of the curve would amount to doubling the cost consumers pay for capacity and requested PJM present more analysis on the expected reliability and cost impacts of the proposed approach.

Economist James Wilson, a consultant for state consumer advocates, gave the example of grafting PJM’s proposal onto a monthly capacity market and questioned if that would result in the possibility of a month with capacity prices increased by a factor of 12.

Graf said he believes it makes sense that the reference resource would be able to meet its annual costs in one month, under Wilson’s example, if that period is determined to hold the entirety of the grid’s reliability risk. He added that PJM’s model wouldn’t increase both the price and the quantity.

“The price in a given season is higher only if the reliability risk is higher and the quantity procured is lower,” he said.

Market Power Mitigation Changes to Must-offer for Intermittents, CPQR

The changes to PJM’s proposal also include removing the must-offer requirement for intermittent resources. Several resource types, including solar, wind and storage, are not subject to the requirement that generators must offer into the capacity market, an exception that PJM had proposed removing in earlier versions of its package. (See PJM Completes CIFP Presentation; Stakeholders Present Alternatives.)

PJM’s Skyler Marzewski said retaining the exception stems from intermittents not possessing a way of physically hedging against the risk that an emergency may occur at a time when they are not able to be online, subjecting them to capacity performance (CP) penalties. He said PJM has not determined if it intends for demand response to be subject to the requirement.

Graf said any resource that would not be required to submit an offer but intends to do so would need to notify PJM sufficiently in advance of the reliability analysis being conducted for that auction.

Emma Nix of Leeward said retaining the must-offer exception likely would lead to Leeward and a coalition of renewable developers dropping plans to offer an alternative to PJM’s proposal. “This is a giant step forward for getting renewable support for PJM’s proposal,” she said.

While the must-offer exceptions were one of the major concerns renewable developers had with the PJM package, Nix said they support requiring intermittents to participate in the capacity market in the long term, so long as the requirement is accompanied by a way of mitigating risk of performance penalties during times those resources can’t be expected to operate.

PJM added detail to its default capacity performance quantified risk (CPQR) calculation, in which it would create a default risk value for each resource class with an option for generation owners to continue to submit unit-specific values instead.

Graf said PJM would look at the 95th percentile of events to estimate a unit-specific analysis of how resources may over- or underperform during modeled performance assessment intervals (PAIs).

The amount of risk determined to be present at the 95th percentile would be multiplied by a cost-of-risk parameter, which in his demonstration Thursday was set at 10%. The cost-of-risk and other parameters in the calculation would be reviewed periodically.

Calpine’s David “Scarp” Scarpignato questioned why the result shouldn’t be the risk at the 95th percentile. Graf said competitive market sellers would be willing to have a small downside as a potential outcome at less than the full amount they stand to gain.

PJM detailed its proposed default Capacity Performance quantified risk calculation during the July 27 CIFP meeting. | PJM

Rework to Performance Assessment Testing

PJM’s proposal to require a physical demonstration that resources can meet their capacity commitments, with penalties for any shortfalls during testing, was revised to measure generators against their daily committed ICAP, rather than against their average seasonal committed ICAP. PJM’s Pat Bruno said the change was made with the understanding that a resource’s capability can change throughout a season.

The test would be based on either operational data for the relevant season provided by the generator or a demonstration that the resource schedules with PJM.

PJM also would be able to initiate two operational tests by scheduling a unit, following its parameter limits and considering the test a success if it is able to come online within a certain amount of its expected time and operates for its minimum run time. Generators would be made whole for costs incurred during testing.

Bruno said tests would be conducted at times that mirror reliability risk, such as cold weather during the winter.

A failed test would result in a forced outage ticket and the unit would be marked unavailable until it indicates to PJM that the issue behind the failure is resolved, or it successfully starts back up. PJM would be able to schedule re-tests, which would result in a capacity deficiency penalty if failed. Re-tests following a failure also would not be eligible for make-whole payments.

Bruno said the deficiency penalties are designed to be imposed following a failed re-test out of a desire to not assess large penalties against a generator for a random mechanical failure and to focus instead on repeated inability to come online.

Vistra’s Erik Heinle asked if resources would have enough time to nominate for fuel prior to a test. Bruno responded they would respect the notification times in a generator’s parameters.

Site Visitation Details

PJM gave more detail on plans to include site visits in its CIFP proposal with the goal of ensuring preparations for extreme conditions are being undertaken and to gather information on any challenges. The current thinking is to have every capacity resource visited around every five years, with a focus on newer generators.

The visits would look to ensure compliance with weatherization requirements and to evaluate if fuel arrangements are being made.

Owners would be given advance notice of any visits and any issues identified would have a “cure period” established with generator input in which no penalties would be imposed. Failure to address issues long-term could result in penalties.

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PJM MRC/MC Briefs: July 26, 2023

Stakeholders Endorse Manual Revisions Conforming to New FERC Requirements

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee endorsed revisions of Manual 14B to align with new language in NERC’s TPL-001-5.1 standard during its July 26 meeting. The changes aim to establish new transmission system performance requirements. (See “Stakeholders Endorse Quick Fix Manual Revisions to Conform to NERC Standards,” PJM PC/TEAC Briefs: July 11, 2023.)

The new language increases the requirements for PJM’s spare equipment standards, creates a new threshold for new outages to be included in the planning horizon and expands the technologies considered part of a component protection system.

The previous NERC standard required that RTOs include outages longer than six months in their planning horizon, which was changed to leave the rationale up to the organizations. PJM proposed looking at upgrades to 230-kV or higher rated equipment or outages that would last longer than five days.

The proposed spare equipment standard would involve PJM reaching out to asset owners to inquire about their policies for maintaining spare equipment to replace any failures that could take a year or two to replace. If those owners don’t maintain an inventory, PJM would conduct a study to evaluate the impact of that equipment failing.

The changes were brought before the July Planning Committee meeting as a quick fix proposal, which allows for a problem statement, issue charge and solution to be brought concurrently and voted on in the same meeting. The manual changes were effective immediately following MRC endorsement.

PJM and Monitor Present Generation Deactivation Issue Charge

PJM’s Paul McGlynn gave a first read of a problem statement and issue charge being drafted in collaboration with the Independent Market Monitor that would investigate increasing the deadline for generators to notify PJM of plans to deactivate, the compensation for generation owners that agree to continue operating facilities beyond the desired deactivation and the triggers offering a generator a reliability-must-run (RMR) contract.

Possible changes to capacity market rules and cost allocation for RMR contracts are out-of-scope in the issue charge. McGlynn said a new senior task force reporting to the MRC is the envisioned route for engaging in the discussion given the number of areas that deactivations impact, including planning, markets and operations.

The only reason PJM currently can provide for seeking an RMR is transmission reliability criteria, but McGlynn said there may be other reasons it wishes to keep a generator operating. The primary rationale the RTO envisions is losing reliability parameters such as black start when a generator goes offline.

Monitor Joe Bowring said the current rules create a lot of confusion and uncertainty, which results in resources being wasted on proceedings. “The rules need to be clarified,” he said.

Vistra’s Erik Heinle questioned if there would be a limiting principal in how long an RMR contract could run for, adding that it could take a long time to replace the black start service provided by a given generator while also discouraging other resources interested in investing to provide that service.

“Before we go down this route, we need to be careful to think of where we may end up,” he said. “We need to be careful of what signals we’re sending to the market.”

McGlynn said PJM’s goal is to keep RMR contracts as limited in use and duration as possible.

“Nobody wins when there’s an RMR. In general, the generators — they’ve already made the decision to deactivate, they want to deactivate it,” he said.

Bowring said he’s concerned about broadening the scope of RMR and believes it should be as narrow as possible but is willing to discuss options.

Dominion’s Jim Davis questioned if part of the rationale for re-evaluating how RMR contracts function is to slow the pace of retirements or make it take longer for them to exit the market. He said the company would not support any changes that could hinder generators’ ability to retire and that one of the purposes of a functional capacity market is to send price signals, including for retirement.

“Ultimately, the decision to retire a resource belongs to the resource owner and that decision is partially made to redirect capital,” he said.

McGlynn said the intent is to look at the process after the decision to retire has been made and support that determination. Senior Vice President of Market Services Stu Bresler added that the longer notice period for deactivation requests is meant to ensure the grid is prepared for resources to go offline.

Susan Bruce, of the PJM Industrial Customers Coalition, said it’s important RMR doesn’t become more attractive than market participation for some resources. She supported discussion of additional triggers for opening an RMR contract and said it also may be prudent to make capacity market changes in scope, given the large changes being considered in the Critical Issue Fast Path (CIFP) process and elsewhere.

Stakeholders also questioned if the voluntary nature of RMR contracts would be in scope, to which McGlynn said his understanding is that PJM can’t force generators to continue operating. Bresler said the issue charge doesn’t explicitly preclude having that discussion but that it may be a question for FERC to decide if PJM has the authority.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said he believes not explicitly ruling out discussion of permitting RMR contracts to maintain resource adequacy is “extremely dangerous” and should be out of scope. The capacity market has its own backstop and RMR should be focused on transmission needs, he said.

Several stakeholders also questioned if the complexity of the topic may not lend itself to the “CBIR Lite” (Consensus Based Issue Resolution) process.

PJM Seeks Stakeholder Process on Reserve Certainty

PJM’s Donnie Bielak presented a wide-spanning issue charge and problem statement on reserve certainty, with several immediate, medium-term and long-term goals for stakeholders to consider in a proposed new senior task force. PJM has seen a decline in the response rate for reserve deployments since the two tiers of reserves were consolidated in a reserve market overhaul implemented Oct. 1. That resulted in PJM increasing the synchronized reserve requirement by 30% this year, overriding stakeholder objections. Bielak said it’s likely nobody was happy with that outcome, and the goal of the new issue charge is to find better permanent solutions. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)

The seven key work activities include reserve performance and penalties, aligning the offer structure with fuel procurement, how resources are deployed and PJM’s target reserve procurement. The proposed timeline for immediate need topics, such as performance and penalties, is to have a solution within a year, while the long-term need to incentivize resource flexibility to match grid needs is set for three to five years.

Heinle said he’s concerned such a wide range of topics could lead to the task force becoming directionless, a fate he said befell the resource adequacy senior task force before it was converted to the CIFP process with a tight turnaround mandated by the Board of Managers. He suggested that finding ways of keeping the work focused on specific areas would help prevent the process from outrunning stakeholders’ best intentions.

Sotkiewicz said he believes more education on the impact of the reserve market changes implemented in October is needed and that the lower response rate could stem from a software or design issue in the new system. He said prices are decreasing leading up to a spin event, which is the opposite of what should be happening. He said PJM rhetoric about generators underperforming and the possibility of enforcement actions has been unhelpful.

“I think there’s something actually much more systemic here that requires more investigation and education … for members to understand that,” he said.

Bruce said more analysis is needed to understand the dynamics of how the increasing number of inverter-based resources on the grid impacts reserves and what their contribution looks like. More education also is necessary to understand what is driving the lower performance. She said she worries if that is not established, it could lead to consumers spending more money on reserves to shore up the issue.

“The solution cannot be let’s just have customers pay more for reserves. Because if we don’t understand what the problem is … that’s just throwing money at the problem,” she said.

Bowring said the issue charge is too broad and should be broken into smaller stakeholder processes. He said he believes synchronized reserves’ failure to respond in recent months has to do with communications and training.

First Read on Peak Market Activity Credit Activity Proposal Expected in August

The Risk Management Committee (RMC) has finalized a slate of packages it plans to vote on during its August meeting, which will be followed by a first read at the MRC during its Aug. 24 meeting. Thomas Zadlo, RMC chair, said PJM is exploring ways of expediting a vote at the RMC to either hold a same-day vote in August following the first read or use other accelerated stakeholder actions to allow the proposal to be implemented in time for winter.

Constellation’s Adrien Ford said the company supports any acceleration that can be found while still respecting the need for appropriate document review.

Proposed changes include introducing minimum exposure and minimum transfer amounts, setting maximum amounts that can be invoiced over given timeframes and changing how collateral shortfalls and surpluses are calculated.

Other MRC Discussions:

    • Several state consumer advocates objected to or abstained from endorsing revisions to Manual 13 stemming from its periodic review, which Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said was due to dissatisfaction that the review of the manual did not take into account how emergency notifications and public messaging performed during the December 2022 winter storm. The changes were approved by acclamation as part of the consent agenda.
    • PJM presented a first read of proposed revisions to Manual 13 to include essential actions in NERC’s cold weather preparations for extreme events. Changes focus on the amount of detail needed in member load-shed plans.

Members Committee Endorses IROL-CIP Cost Recovery

The Members Committee voted to endorse a PJM-sponsored proposal to create a cost-recovery mechanism to allow generators to recoup expenses incurred by making upgrades after being designated critical to the derivation of an interconnected reliability operating limit (IROL) under NERC’s critical infrastructure protection (CIP) standards. The acclamation vote had six objections and 11 abstentions. (See “MRC Endorses IROL-CIP Cost Recovery,” PJM MRC/MC Briefs: June 22, 2023.)

PJM’s Darrell Frogg, who presented to the MC Wednesday, has compared the cost-of-service payment structure in the proposal to the cost-recovery structure for black start service, with generators submitting their costs to the RTO and Monitor to review and costs allocated to market participants.

The proposal was opposed by the Monitor, who presented a competing proposal in the Operating Committee, on the grounds the costs should be included in generators’ market offers and it could become a slippery slope to new non-market cost-of-service structures for other services, a concern he returned to Wednesday. He argued there is no explanation for what differentiates IROL-CIP-related costs from other services generators include in their offers.

Bruce said some industrial customers abstained from the vote over concerns the process PJM uses to select IROL-CIP facilities may lead to increased costs if PJM designates one generator, it makes the requisite upgrades and then PJM shifts the designation to a different resource. She said the “heartache” isn’t with having to pay for reliability upgrades, but rather with cost minimization.

Poulos said some advocates who abstained from the MRC vote switched to being in opposition because of a concern the proposal turns away from using markets and toward a less transparent cost-of-service approach.

PJM Assistant General Counsel Thomas DeVita said he believes the proposal included a healthy balance between allowing generators to recover costs while protecting consumers. He said costs incurred before the critical designation or those that would have been made regardless can’t be included and the proposal also includes provisions to avoid double counting.

“We have some very significant and serious protections built in for customers,” he said.

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NHTSA Proposes 66.4-mpg Fuel Efficiency for Passenger Cars by 2032

The National Highway Traffic Safety Administration (NHTSA) on Friday issued a proposal for a major increase in national fuel efficiency standards for cars, light-duty trucks and some heavy-duty vehicles, aimed at saving drivers money on gasoline while cutting both U.S. greenhouse gas emissions and dependence on foreign oil.

The 696-page Notice of Proposed Rulemaking would require automakers to hit a fleetwide fuel Corporate Average Fuel Efficiency (CAFE) of 66.4 mpg for passenger cars and 54.4 mpg for light-duty trucks for their 2032 models.

The standard for heavy-duty pickups and vans (HDPUVs) — defined as between 8,501 and 14,000 pounds — would taper off from 4.4 gallons needed to drive 100 miles in the 2030 model year to 2.6 gallons in 2035.

However, the NHTSA qualified those numbers by noting “that real-world fuel economy is generally 20 to 30% lower than the estimated required CAFE level.”

The NHTSA requirements for fuel efficiency for 2023 models are 50.5 mpg for passenger cars and 35.8 mpg for light-duty trucks, according to figures from the Department of Energy. According to the NHTSA, passenger cars include sedans, station wagons and two-wheel drive crossovers and SUVs, while the light-duty truck category covers four-wheel-drive SUVs, small pickup trucks, minivans, and passenger and cargo vans.

The proposed standards, covering model years 2027-2032, would push automakers to improve fuel efficiency 2% per year for passenger cars and 4% per year for light-duty pickups. The standards for HDPUVs would tighten 10% per year from 2030 to 2035.

The current standards for passenger cars and light trucks end in 2026. The NHTSA said the 2030 starting date for the HDPUV standard is because of “statutory lead time constraints” but did not provide further details.

Previous CAFE standards have set combined fuel efficiency targets for passenger cars and light trucks. However, the NHTSA said, it was setting different standards for the two categories because “manufacturers have already made substantial progress in technology application to passenger cars, such that the possibility for further fuel economy improvements … is relatively limited.

“The agency believes that there is more room to improve the fuel economy of light trucks, in a cost-effective way, and that the benefits of requiring more improvement from light trucks will be significant given their high usage and the fact that they make up an ever-larger percentage of the overall fleet.”

The combined standard for passenger cars and light trucks would be 57.8 mpg in 2032, the agency said.

The NHTSA estimates that the proposed standards would slash fuel consumption by 88 billion gallons for passenger cars and light-duty trucks and 2.6 billion gallons for HDPUVs through 2050. The resulting reductions in carbon dioxide emissions would be 885 MMT for passenger cars and light-duty trucks and 22 MMT for HDPUVs.

The agency estimates that savings from the proposal would exceed costs by $18 billion but that the savings consumers see at the pump would be more modest. For example, lifetime fuel savings of $1,043 for more efficient passenger cars would be offset by an increased cost of $932, delivering net savings of $111 in the 2032 model year. Lifetime net fuel savings for HDPUVs would be about $300 in the 2038 model year.

The release of the NOPR starts a 60-day comment period, and the NHTSA will hold at least one virtual public hearing during that time.

NHTSA vs. EPA

The NHTSA CAFE standards follow proposed standards for tailpipe emissions that EPA issued in April. (See EPA Issues Emissions Rules Aimed at Boosting EVs.)

EPA estimates those standards would cut emissions from light- and medium-duty vehicles by 7.3 billion MT of CO2 between 2027 and 2055 and projects net benefits of $1.6 trillion. Proposed standards for heavy-duty vehicle rules would save 1.8 billion MT of CO2 and yield $320 billion in benefits.

“I want to make clear that EPA and NHTSA will coordinate to optimize the effectiveness of both agency standards while minimizing compliance costs,” acting NHTSA Administrator Ann Carlson told The Associated Press.

The proposed levels were chosen as both technologically and economically feasible, the agency said, noting that by statute, it is not allowed to factor electric vehicles into its efficiency standards, a major difference with the EPA standards, which are aimed at boosting vehicle electrification.

At the same time, automakers can use electric vehicles to meet the standards, the NHTSA said.

Reactions

Sen. Ted Cruz (R-Texas) slammed the proposal as an attack “on affordable gas-powered cars and trucks” and a “de facto EV mandate” that would raise prices and hurt national security.

John Bozzella, CEO of the Alliance for Automotive Innovation, said efforts to align the two standards are “encouraging” but they could still cause problems and extra costs for automakers and consumers.

“Conflicting and overlapping rules are complex and expensive,” Bozzella said in a statement released Friday. “If an automaker complies with EPA’s yet-to-be-finalized greenhouse gas emissions rules, they shouldn’t be at risk of violating CAFE rules and subject to civil penalties that levy costs on consumers and manufacturers — but deliver no corresponding environmental benefits.”

He called for “a single national standard to reduce carbon in transportation — one vehicle fleet and one national standard.”

While earlier raising concerns about penalties for automakers not meeting the NHTSA standards, General Motors released a statement Friday welcoming “the intent to align NHTSA and EPA standards and providing flexibility to industry to achieve these targets.”

The company has committed to selling only all-electric new vehicles by 2035.

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DC Circuit Upholds Tx Cost Allocation for Rhode Island Solar Project

The D.C. Circuit Court of Appeals on Friday denied a pair of petitions by the Rhode Island-based company Green Development over FERC’s approval of transmission charges connected to a proposed solar project. The court determined that Green Development’s four main issues with FERC’s approval lacked merit.

Green Development is the developer of four solar projects totaling about 40 MW in Rhode Island. The company requested to connect the projects to the local distribution system, owned and operated by Narragansett Electric Co., a former subsidiary of National Grid now owned by PPL Electric Utilities under the name Rhode Island Energy.

Narragansett and New England Power, also a subsidiary of National Grid, determined the solar project would require significant upgrades to the distribution and transmission systems, including a new substation, costing about $18 million, with the costs ultimately passed down to Green Development.

FERC denied the bulk of Green Development’s arguments opposed to this cost allocation in orders issued in September 2021 and February 2022. The commission upheld its findings of both orders upon rehearing (EL21-47 and ER22-707).

Green Development’s petition to the D.C. Circuit, argued in March of this year, alleged FERC mischaracterized some of the company’s arguments, failed to justify its jurisdiction over the upgrades, misinterpreted the definition of “direct assignment facilities” in the ISO-NE tariff and that the RTO and New England Power failed to file a new application for transmission service in accordance with the tariff.

In its ruling on Friday, the D.C. Circuit sided with FERC, rejecting all four of these clams.

“Each of Green Development’s four grounds for vacatur lacks merit. Accordingly, we deny the petitions for review,” wrote Circuit Judge Karen L. Henderson.

Green Development declined to comment on the ruling.

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SPP Planning Response After FERC Rejection of Tariff Revision

ST. PAUL, Minn. — SPP legal staff said last week it is evaluating whether to modify and refile a tariff revision to allocate “byway” transmission projects on a case-by-case basis or to seek a rehearing of the order.

Paul Suskie, SPP | © RTO Insider LLC

General Counsel Paul Suskie told the grid operator’s Regional State Committee July 24 that staff is reviewing its options following FERC’s rejection of its proposed methodology. (See FERC Reverses Course on SPP Byway Cost Plan.)

“We will do that in our ordinary course,” Suskie told the committee, composed of SPP’s state regulators. “From a timing perspective, we could probably get a result back from FERC and an approval rather than going through the appeal process.”

Asked whether SPP could work the two paths in parallel, Suskie warned the RSC that doing both at the same time would create ex parte limits when communicating with FERC.

In a July 13 order, FERC unanimously reversed a 2022 decision approving the RTO’s process to allocate byway transmission projects — facilities rated at 100 to 300 kV — after rehearing arguments raised by several SPP members. The commission rejected SPP’s proposed methodology without prejudice and dismissed a November compliance filing as moot (ER22-1846).

FERC said SPP failed to prove its proposal to regionally allocate 100% of a byway facility’s costs on a postage-stamp basis would result in outcomes that are just and reasonable and not unduly discriminatory or preferential.

The grid operator currently allocates one-third of byway projects’ cost to the RTO footprint, with customers in the transmission pricing zone where the project is built being allocated the rest. “Highway” projects — those larger than 300 kV — are allocated RTO-wide.

RSC and its Cost Allocation Working Group have been working on the issue since 2017. It was one of 21 initiatives developed by the Holistic Integrated Tariff Team before the COVID-19 pandemic. Stakeholders and staff have produced reports and white papers that led to an earlier tariff revision being rejected by FERC in 2021.

“It’s probably an understatement to say I’m disappointed to see the FERC action,” said RSC President Andrew French, with the Kansas Corporation Commission. “I do think we have an opportunity here to see if maybe there’s a better approach, maybe even an approach that could address some of the concerns in our stakeholder process and hopefully we come up with something better. This is something that we have developed an extensive record on.”

Dana Shelton, legal counsel to the Louisiana Public Service Commission, pointed out that the agency, along with those of New Mexico, Oklahoma and Texas, opposed the revision request when it came before the CAWG in December 2021. FERC Commissioner Mark Christie noted the lack of “uniform” state support for the proposal in a concurrence to the order.

“It was on what we view as illegitimate cost-allocation principle … and an unjust and unreasonable rate allocation,” Shelton said. “We do continue to have concerns along those lines. I would ask that SPP and all concerned keep that in mind.”

“It was an issue of cost allocation and equitable treatment for utilities,” Texas Commissioner Will McAdams said. “Texas shared those concerns and would stand on that position.”

McAdams Elected RSC’s Vice President

RSC members elected McAdams as their vice president. He replaces Geri Huser, who stepped down from the Iowa Utilities Board in May, four years short of her term’s expiration.

Minnesota’s John Tuma was elected to replace McAdams as the committee’s secretary and treasurer.

SPP CEO Barbara Sugg recognized McAdams during her president’s report to the board for his “exceptional leadership” of the stakeholder group addressing the RTO’s resource adequacy issues. (See SPP REAL Team Endorses Winter Resource Requirement.)

“I have heard nothing but accolades for your leadership,” she said. “I’m just so impressed with the joint nature of that group and the value that they are going to bring to the RSC, to the board, to the Members Committee, really to all SPP stakeholders.”

The RSC also approved South Dakota’s Kristie Fiegen to chair the nomination committee that will select officers for 2024. Arkansas’ Justin Tate and Oklahoma’s Todd Hiett will serve with Fiegen.

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Down Day: Xcel, AEP, CenterPoint Shares Slide After Earnings

Xcel Energy highlighted a busy day for utility earnings calls Thursday with weaker results the company blamed on inflationary pressures and a lower-than-expected return on equity from a rate case in its home state of Minnesota.

The Minnesota Public Utility Commission in June approved a $306 million, or 9%, rate increase over three years for Xcel, below recommendations from the state’s Department of Commerce and an administrative law judge. Xcel initially requested a $677 million, or 21%, increase before dropping its ask to $498 million and then $400 million.

The Minneapolis-based company reported earnings of $288 million ($0.52/share) for the quarter, down from $328 million ($0.60/share) from a year earlier.

CEO Bob Frenzel said the company is working to offset the effects of the headwinds and is continuing to “lead the nation’s clean energy transition.”

In June, the PUC also approved Xcel’s plan to construct a multi-day energy storage system that will test Form Energy’s 10-MW/1,000-MWh iron-air battery system at the utility’s 710-MW Sherco solar site. The battery is expected to come online in 2025. (See “Long-duration Storage is Key,” Overheard at EEI 2023.)

“We’ve always been focused on new technology, new research, development and deployment of new technologies to achieve our 100% goal,” Frenzel said, referring to the company’s first-in-the-nation commitment to 100% carbon-free electricity. “Long duration energy storage is a critical part of the energy future. A 100-megawatt-hour battery … [is] a nice asset class as we think about periods when the wind doesn’t blow and the sun doesn’t shine.”

Frenzel also addressed a recent report following an investigation by the Boulder County (Colo.) Sheriff’s Office into a 2021 wildfire that caused about $2 billion in property losses. The report found Xcel subsidiary Public Service Company of Colorado (PSCo) responsible for one of two ignitions. Xcel disclosed the report in its earnings release and said that if PSCo is found liable and is required to pay damages, the amounts could exceed insurance coverage of approximately $500 million.

“Because of the pending litigation that has been filed, we’re not in a position to discuss the fire in more detail at this time,” Frenzel said. “We will vigorously defend ourselves and move forward to presenting our position in court.”

Xcel’s share price dropped $2.18 (3.35%) during a down day on Wall Street, closing at $62.87. The Dow Jones Industrial Average lost 237 points, ending a historic streak of 13 straight gains.

AEP Continues with Asset Sales

American Electric Power said Thursday that the “de-risking” and “simplification” of its business continues to pick up speed with two non-core transmission ventures being put up for sale.

CEO Julie Sloat told financial analysts during the company’s quarterly earnings call that AEP will soon launch the sale of its interests in the Prairie Wind and Pioneer transmission projects. The former are 345-kV facilities in Oklahoma and the latter 765-kV facilities in Indiana.

AEP could also soon put its share of Transource Energy, a competitive transmission developer, on the block once it completes a strategic review.

AEP also plans to close the sale of its 1.37-GW unregulated renewables portfolio to IRG Acquisition Holdings in August and is on track with other transactions involving its AEP Energy retail and AEP OnSite Partners distributed resources businesses and its 50% share in the New Mexico Renewable Development joint venture.

“Our ongoing active management of the company strengthens our ability to prioritize investments in our regulated businesses,” Sloat said.

The Columbus, Ohio-based company delivered second-quarter earnings of $521 million ($1.01/share), compared with earnings of $525 million ($1.02/share) for the same period a year ago.

During the quarter, AEP received regulatory approval to add nearly 2 GW of new wind and solar generation in Oklahoma, Arkansas and Louisiana. It also has approvals in place for $5.2 billion of its five-year, $8.6 billion regulated renewables capital plan and has filed for approval of $1.7 billion in additional renewable projects.

AEP’s share price closed Thursday at $85.26, a drop of $2.35 (2.6%) on the day.

CenterPoint Energy Takes $74M Hit

CenterPoint Energy (NYSE: CNP) also reported quarterly financial results on Thursday, delivering earnings of $106 million ($0.17/diluted share) that included a loss and expense of $74 million ($0.12/share) related to the divestiture of Energy Systems Group (ESG).

The Houston utility earned $179 million ($0.28/diluted share) during the second quarter a year ago.

CenterPoint sold its interest in ESG for about $157 million to EEG Holdings in May. ESG offers energy efficiency and sustainable energy solutions.

The utility’s share price closed at $30.36 Thursday, an 85-cent loss.

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NJ BPU Backs Building Decarbonization Plan Despite Opposition

New Jersey’s Board of Public Utilities (BPU) agreed Wednesday to vigorously promote a statewide shift from fossil-fuel space and water heating systems to electric appliances as part of a three-year energy efficiency program.

The board voted 4-0 to approve the Triennium II proposal to cut building emissions through the use of demand-response programs and voluntary electrification backed by incentives as the state seeks to reach 100% clean energy by 2035.

A key element of the framework, which will be in effect from July 1, 2024, to June 30, 2027, is a series of building decarbonization (BD) “startup” program plans designed to encourage customers of all kinds — but especially residential and multifamily dwelling customers — to switch from fossil-fuel water and space heaters to electric appliances.

Although the BPU initially floated a budget of about $150 million over three years for the building decarbonization programs, the latest version sets out a more “robust” estimate of $84 million in the first year, $120 million in the second and $144 million in the third, for a total close of $348 million. The final figure, however, will be determined by the utilities in the state working with the BPU board, the order says (QO19010040, QO23030150, QO17091004).

Contentious Issues

The Triennium is one of several initiatives begun by Gov. Phil Murphy (D) to decarbonize buildings by reducing fossil fuel use and increasing electricity use. In February, Murphy said the state should have 400,000 additional dwelling units and 20,000 additional commercial spaces “made ready” for electrification by the end of 2030 (Executive Order No. 316).

Some electrification supporters say the plans are too timid. Opponents argue that switching to electrical space and water heating systems is expensive and decry what they see as a “mandate” by the Murphy administration to make the shift. (See NJ Building Decarb Plan Garners Support, Criticism.)

BPU President Joseph L. Fiordaliso said the framework, approved 4-0, “without a doubt … kickstarts to the next generation of energy efficiency in New Jersey.”

“It will deliver significant emissions reductions through critical investments in efficiency,” he said. “That importantly, will help save ratepayers money.”

He criticized “fear mongering” and “misinformation” about the program, particularly the suggestion that the state is forcing people to switch to electricity.

“Let’s be clear: We are not mandating anyone to give up their gas stove,” he said. “This program is about giving people more choices and more chances to create a more sustainable and more affordable energy future.”

Shifting The Burden

But Ray Cantor, deputy chief government affairs officer for the New Jersey Business and Industry Association, one of the state’s largest business groups, said the program “shifts the cost of an ineffective building electrification policy onto the backs of ratepayers who already pay some of the highest electric rates in the nation.”

“A 100% building electrification policy is not the best approach,” he said. “There has been no comprehensive planning or investment in either the transmission or generation systems adequate to support a massive building electrification policy. … It is irresponsible for the state to move ahead with new sources of demand and hope that the grid and generation capacities will be there.”

In addition, he said, “there are other, and perhaps less costly and more efficient options, to decarbonize our building sector.”

Adopting Heat Pumps

The Triennium II framework, which follows an earlier three-year plan in place until June 30, 2024, includes goals, targets, performance incentive mechanisms and other strategies to improve the state’s energy efficiency efforts and make them accessible throughout the state, especially to low- and moderate-income customers. The BPU drafted the final version after two lengthy public hearings on the proposal in June. (See NJ BPU Outlines $150M Building Decarbonization Plan.)

Startup programs proposed in the Triennium include providing customer incentives to persuade customers to switch from fossil fuels to electricity. The program places a high priority on consumer adoption of heat pumps, which the BPU’s order says generate two to four times more energy than they consume — compared to regular appliances that generate less energy than they consume.

The programs should be created by the electric distribution companies and should “prioritize customer incentives for electric space and water heating in the residential and multifamily sectors, focusing on switching from delivered fuels to electric heat pumps,” the framework said. Programs also should enable gas distribution companies to propose hybrid solutions to their customers, such as switching from gas to electric air conditioning but maintaining a gas-powered heat furnace.

The plans also call for the implementation of demand response programs in which customers receive a signal urging them to reduce their energy consumption when demand is high and the grid stressed, such as in especially hot or cold weather. The BPU is looking to utilities to design the programs so they are easy for customers to use and rely on smart meters and thermostats.

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FERC Rejects Call for CIP Standard Updates

FERC on Thursday denied a petition from the Secure-the-Grid Coalition calling for new reliability standards to meet the growing threat of physical violence against the electric grid, saying the proposal was unnecessary in light of other work serving the same goal (EL23-69).

The coalition filed its petition in May, after NERC submitted a report on potential changes to CIP-014-3 (physical security) to the commission. (See NERC Says Changes Coming to Physical Security Standards.) FERC had ordered the report in response to physical security incidents last year, primarily the Dec. 3 gunfire attack on two substations in North Carolina that left 45,000 customers without power for as long as four days.

FERC Chairman Willie Phillips | FERC

The commission had asked NERC whether the assessments that CIP-014-3 required of transmission owners (TO) to evaluate the vulnerability of their facilities were adequate to identify facilities in need of strengthening. In its report, the ERO said this was the case, and that expanding the criteria for TOs to check would not identify any additional critical facilities.

Secure-the-Grid felt the response was not sufficient and urged the commission to order NERC to revise the standard. Its petition argued that the standard should “require industry to establish new metrics for risk assessments” beyond the frequency and consequence of attacks. Suggested metrics included “known vulnerabilities, attacker capabilities and attacker intentions.”

The coalition also pointed out that the applicability of CIP-014-3 is determined by definitions of the grid and critical assets in CIP-002-5.1a (cyber security — BES cyber system categorization). Therefore, Secure-the-Grid argued, those definitions must be expanded, requiring revisions to the latter standard as well.

ERO Says Needed Work Already Underway

NERC and several electric industry trade groups pushed back hard on the coalition’s claims last month in separate filings. (See NERC, Trade Groups Oppose Call for Quick Fix on CIP Standards.) The ERO said it plans to review CIP-014-3, both in an Aug. 10 joint technical conference with FERC and two standards development projects, one of which will also examine CIP-002-5.1a. A new directive from FERC would only interfere with these efforts, which are the “appropriate public processes” for considering the coalition’s concerns, NERC said.

The American Public Power Association, Edison Electric Institute, Large Public Power Council, National Rural Electric Cooperative Association and Transmission Access Policy Study Group raised similar concerns with Secure-the-Grid’s petition. They added that the coalition’s sole justification for calling for revisions to the standards was the growing frequency of physical security incidents on the grid, but said the group failed to prove that a new or revised standard was an appropriate response.

In its decision Thursday, FERC agreed with NERC that the joint conference and standards projects “provide the appropriate forums for addressing the petitioner’s concerns.” While the commission acknowledged Secure-the-Grid’s concerns and said that “the physical security of the [grid] is of paramount importance,” it also said the work already underway is “adequate” for addressing the grid’s physical security needs.

FERC Clarifies Cyber Incentives

The commission also provided clarification on an order it issued earlier this year establishing financial incentives for voluntary cybersecurity investments by electric utilities, fulfilling a request submitted by NRECA (RM22-19).

NRECA filed a request for clarification or rehearing of FERC Order 893 in May. The trade group took issue with the part of FERC’s final rule providing that utilities may qualify for incentives through investments needed to establish compliance with NERC’s Critical Infrastructure Protection (CIP) standards that are not yet enforceable. (See FERC Issues Cyber Incentives Order.)

Specifically, NRECA claimed that the term “effective date” appeared in FERC’s order referring to both the date that the commission issues an order approving a new standard and the date that the standard becomes enforceable. It asked that the commission clarify whether a utility:

    • Must demonstrate full compliance with the relevant CIP standard to be eligible for the incentive;
    • May receive the incentive for investments made before the date NERC submits a proposed standard to the commission or the date FERC issues an order approving the standard; and
    • Faces any requirement concerning how long before the effective date of the standard an investment must be made in order to qualify for the incentive.

FERC explained in its response that the new rule requires utilities to demonstrate that they will make their investments after the effective date of approval of the appropriate standard, but before its enforceable date. It said that a utility attempting to claim the incentive “must achieve compliance” with the standard to satisfy the requirement.

In addition, FERC affirmed that the only time requirement regarding the cyber incentives was that the investments be made after the approval of the standard and before its effective date, meaning there is no minimum time requirement before the effective date for investments to qualify for the incentive.

NRECA also asked FERC to clarify whether utilities that sell energy, capacity or ancillary services at market-based rates may also sell at separate cost-based rates that account for the cybersecurity investment incentives. The commission said its order “does not preclude” such sales.

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NYPA Taking to the Skies with Expanded Drone Fleet

The New York Power Authority is going all-in on drones, launching a $37.2 million program to expand their use for inspections as a safety, efficiency and economy measure.

NYPA’s Board of Trustees on Thursday approved an initial $9.6 million allocation to launch the five-year Unmanned Aerial System program.

Drones have been gaining favor for years as a tool to inspect transmission lines. It is much slower to have a line person climb up for a visual check and much more expensive to fly over in a helicopter. And with both of those options, the implications of an accident are much worse.

Even a substation inspection is safer with a drone, as it does not put anyone close to high voltage.

The nation’s largest state-owned utility operates 1,400 circuit-miles of transmission lines. But it also has bridges, dams, waterways, fossil fuel generating stations and conventional and pumped hydropower facilities to monitor and maintain.

NYPA’s drones are equipped with high-resolution cameras and sensors that can detect flaws not visible to the human eye. The authority plans to make as much use of them as it can.

“By bringing more drones into our day-to-day operations, we can better harness the benefit of automation, safety and consistency across our assets while reducing costs and insuring a more reliable power supply,” NYPA Robotics Program Manager Peter Kalaitzidis said in a news release. “Inspections can be improved and expanded to include other areas and assets. With use of drone technology, we can more easily capture the real-world state of our operations to support real-time decision-making.”

NYPA has trained nearly 100 pilots and has been getting its drones out to its operating units to allow them to figure out their own best uses for the technology.

The goal now is to buy more hardware and software; expand and improve training; standardize policies and procedures; and develop a platform from which to gather and make the best use of data recorded on each flight.

The authority is keeping its regulatory compliance up to date as well. Earlier this year it received its first waiver from the Federal Aviation Administration to operate drones beyond the pilot’s line of sight. NYPA said this will be useful at its Blenheim-Gilboa Pumped Storage Power Project, which sprawls more than 2 miles across very rugged terrain.

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CCAs Challenge California PUC on RA Ruling

A group representing California’s community choice aggregators is asking regulators to reconsider a decision that blocks CCAs from expanding if they have had resource adequacy deficiencies in the past two years.

The California Public Utilities Commission on July 5 issued the decision, which adopts local capacity obligations for 2024 to 2026 and refines the commission’s resource adequacy program.

The California Community Choice Association (CalCCA) filed a rehearing request Wednesday, saying the decision contained numerous “legal errors.”

CalCCA argues that the CPUC exceeded its jurisdiction over CCA implementation plans and impaired customers’ right to aggregate their loads with a CCA. The commission failed to act in a nondiscriminatory manner by prohibiting expansion of CCAs and electric service providers, but not investor-owned utilities, CalCCA said.

“The CPUC has given itself new unauthorized powers to needlessly discriminate against CCAs and prevent their growth,” CalCCA Executive Director Beth Vaughan said in a statement. “The decision literally blocks communities from exercising their legal right to aggregate and provide customers with a choice of energy providers.”

California has 25 CCA programs in operation, serving more than 14 million customers. The CCAs buy electricity for participating communities, in place of investor-owned utilities, with an emphasis on clean energy.

RA Obligations

The CPUC said in its decision that load-serving entities (LSEs) have been failing to meet resource adequacy obligations. The decision said seven LSEs had month-ahead deficiencies in 2021 and five in 2022. Some LSEs have repeatedly failed to meet their RA obligations, the decision said.

“Even more concerning, some LSEs submitted implementation plans to expand their customer load by increasing their service territory, even as they have been unable to secure sufficient capacity to meet their RA obligations and serve their existing customers,” the decision said.

Under the decision, an LSE isn’t allowed to expand its service territory if it hasn’t complied with RA requirements in the previous two calendar years. A deficiency doesn’t count toward the expansion ban if it’s less than 1% of the LSE’s requirements.

The restriction applies to a CCA’s expansion of its service territory, not to growth within its existing territory.

The CPUC decision addresses the nondiscrimination issue by noting that investor-owned utilities are providers of last resort and therefore legally distinct from other LSEs.

CalCCA said the CPUC may or may not rule on its rehearing request. If there’s no ruling by Sept. 26, the request is considered denied. The group said it would then decide whether to take the issue to a state appeals court.

Penalty System

The CPUC sets resource adequacy obligations for LSEs that are enforced through citations and fines.

In a previous decision, the CPUC added a point accrual system to the program’s penalty structure to increase penalties when an LSE repeatedly falls short of RA obligations.

CalCCA said newer market entrants such as community choice aggregators and direct access providers are hardest hit by resource shortages. In contrast, investor-owned utilities have “legacy” supplies, the group said in a resource adequacy section on its website.

CalCCA said the CPUC should do more to address the RA problem.

“RA penalties for LSEs unable to secure supply in a deficient market do nothing to get new resources in the ground, and they unnecessarily add to customer costs and indirectly increase the cost of supply,” CalCCA said.