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July 3, 2024

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NJ Senator: Failing State Grid Can Stymie Clean Energy Efforts

The biggest obstacle to New Jersey’s adoption of clean energy is the state’s inadequate grid and a reluctance to make the kind of investments needed for the grid to handle a surge in solar and wind power, a state senator said at a clean energy conference. 

Sen. Bob Smith (D), chairman of the Senate Environment and Energy Committee, which initiates much of the state’s clean energy legislation, said that despite New Jersey’s aggressive agenda, the state is far short of creating a grid that can accept numerous clean energy connections. 

Smith spoke at the Clean and Sustainable Energy Summit 2024 on May 2 at Montclair University. Transmission issues were prominent, but some speakers differed with Smith’s analysis, praising initiatives such as the state’s aggressive solicitation of projects to develop onshore and offshore transmission links to connect offshore wind (OSW) projects with the grid.  

Smith said his committee got some “relatively modest” climate change initiatives passed but has struggled with major initiatives to prepare the grid for the task of handling the state’s shift to an energy system focused almost entirely on electricity. 

“We’re in trouble, and we’re not moving fast enough to solve the problem,” said Smith, the conference’s morning keynote speaker. He called for a “wartime mobilization for global climate change.”  

“We have this 19th-century view that you should not spend an extra one-tenth of a cent in trying to upgrade your grid,” he said. The attitude is “build what you basically need and maybe only for the short term. We don’t have long-term thinking, either at the federal level, FERC, or the regional entity PJM or in New Jersey. So we now have a grid that is held together by duct tape, and not very good duct tape.” 

Smith noted that Gov. Phil Murphy (D) marked Earth Week by citing his administration’s clean energy initiatives, including the allocation in his 2024/25 budget of $40 million for grid upgrades, to use a federal match. But Smith called it “literal spit in the bucket of what we need to do to make our grid work.” 

Commissioner Marian Abdou | © RTO Insider LLC

In an interview with NetZero Insider after his speech, Smith said he’s uncertain whether a bill he co-sponsored, S258, which would allocate $300 million to grid upgrades to use $200 million more in federal funds, will advance in the near future. Introduced in January, the bill in March passed out of the Senate Environment and Energy Committee but has yet to move in the Senate Budget and Appropriations Committee or the Assembly. 

Smith said educating legislators is not too dissimilar from educating the citizenry, in the sense they often get motivated only by a hurricane, flood or other crisis.  

“People have to understand how serious this is,” he said. “We have got to get their attention.” 

Marian Abdou, a commissioner of the New Jersey Board of Public Utilities (BPU), was more measured in her assessment of the state’s position. She said that “with an increase in demand for electricity and expanding our renewable energy resources, we need to ensure the grid can handle this influx.”  

Standing in for BPU President Christine Guhl-Sadovy, who was unable to attend, Abdou noted the board on April 30 approved a package of grid modernization rules that could help streamline the interconnection process. 

“Stable infrastructure is a critical piece of building a clean energy future, and for New Jersey, it centers on modernizing our electric grid,” she said. 

Balancing New and Declining Energy Sources

Matthew Bernstein, senior policy advisory, governmental services at PJM, addressing a panel on energy security, said the RTO faces a series of the challenges but already has recognized, and responded to, the need for “proactive transmission planning,” and an improved connection process. 

The RTO is working with stakeholders on a long-term framework that would allow it to get ahead of anticipated generator deactivations and load growth and focus beyond a “five-year regional transmission expansion planning process,” he said. 

Mathew Bernstein, PJM | © RTO Insider LLC

The RTO is addressing the ongoing backlog of new projects awaiting connection through reforms that would allow the company to “expeditiously move these projects through the interconnection queue,” Bernstein said. 

“We implemented stronger guardrails around speculative projects to show that the projects that are entering the queue really do have the potential to be built,” he said. “We’re already seeing a lot of projects make their way through the queue in a much more timely manner.” 

By the middle of 2025, PJM expects to have studied and processed projects with a combined capacity of about 72,000 MW, he said. And over the next three years, all 230,000 MWs of proposed projects will be studied by PJM and the response delivered to their developers, he added. Still, about 40,000 MW of generation that was passed out of the PJM connection process has not been developed due to obstacles such as supply chain issues, inflation and financial pressures, he said. 

PJM electricity demand growth | PJM

The RTO also is working to balance the retirement and closure of fossil fuel generators with the arrival of clean energy generators, to create a steady power flow that matches demand, Bernstein said. Load growth has increased dramatically, driven by “significant electrification of the transportation sector, heating equipment and other dwelling units, as well as the proliferation of data centers throughout the region.” 

In its annual forecast, PJM predicted from 2014 to 2024 that load growth would decline slightly, Bernstein said. But the RTO this year predicted summer peak load will grow by about 1.7%. That dynamic has raised questions about whether the RTO has “sufficient generation available to meet our demand today, and in the future, not just the actual demand, but also have sufficient reserves in place for contingencies,” Bernstein said. 

“If the load continues to grow at the rate that we are expecting, and we are seeing resources retire, this will become a problem,” he said “It’s not a problem that we’re seeing this moment today. But over the coming decade, this will become a problem if these (new) resources aren’t coming into the system in a timely manner.” 

Linking OSW to the Grid

Damian Bednarz, managing director for Attentive Energy Two, which is developing a 1,342-MW OSW project off the Jersey Shore, agreed with Smith that long-term planning will be “critical” to the sector. The state has shown foresight in its “prebuild” solicitation seeking proposals for transmission infrastructure that will link OSW projects with the grid on land, Bednarz said.  

If completed, Attentive Energy Two and a second project, Leading Light Wind, together would bring about 3,742 MW of capacity through Sea Girt, in Monmouth County. The projects would connect to the grid at the Larrabee Collector Station, an entry gateway the BPU instigated in a solicitation held under the FERC State Agreement Approach. 

Damian Bednarz, Attentive Energy | © RTO Insider LLC

Bednarz, referring to Smith’s comment that the state needs a “wartime mobilization,” said he believes “offshore wind is that counterattack.” He added that “if we’re going to have a counterattack in this effort to combat climate change, it takes a deep level of investment into not just the generation, but all aspects, to make this reality.” 

Attentive Energy was the developer of one of three projects canceled by the New York State Energy Research and Development Authority (NYSERDA) after they had been approved in the state’s third solicitation, on Nov. 17. NYSERDA said the designated developers could not finalize their agreements due to changes in several factors, in particular a decision by GE Vernova to halt development of an 18-MW variant of its Haliade-X turbine and to remain making smaller, less efficient turbines.

Bednarz called the cancellations “incredibly frustrating” for many stakeholders, but he said the sudden, dramatic project meltdowns may be dissipating. Attentive Energy’s New York project suffered from the change in technology due to GE Vernova’s decision, rather than routine supply chain price hikes, he said. 

“You also have a lot of states looking at the solicitations differently, I think, through some hard trial and error,” he said. “In key aspects of the solicitations, you have an inflation adjuster additive that could potentially push back on some of the supply chain risks, and then increased costs that can vary being factored in.“ 

“And I believe New Jersey, going forward, as well is going to have a lot of those things built into solicitations that prevent some of that increase in costs,” he said. 

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FERC Approves NYISO Request to Lower NYC Capacity Requirement

FERC on May 6 granted NYISO’s waiver request to update its installed capacity requirement for New York City in the 2024/25 capability year, which began May 1 (ER24-1800). 

The amount of capacity the market is set to procure for Zone J (i.e., the city) was off because NYISO originally used the wrong historical data to calculate the transmission security limit (TSL) floor for the zone, from 2017-2021 instead of 2018-2022. The TSL floor is an input for the locational capacity requirement (LCR) and essentially acts as the minimum LCR. 

The correct inputs lead to a TSL floor value (and LCR) of 80.4% instead of 81.7%. NYISO told FERC in its request that the waiver would save load-serving entities in the city about $15 million to $20 million per month in capacity costs. 

NYISO discovered the issue late and only filed its request on April 18, but it immediately reported the issue to FERC’s Office of Enforcement and the ISO’s Market Monitoring Unit, Potomac Economics, on April 10, as required by its tariff. The grid operator said it acted swiftly to analyze the error and determine its impact and potential remedial impacts. It is also trying to understand how it happened and avoid it going forward, it said. 

The waiver is the narrowest feasible solution to the problem created by the error, NYISO said. Only Zone J needs to be fixed, and the correction would not cause any reliability issues or changes to the reserve margin set for the New York Control Area. 

The waiver also addresses a concrete problem by avoiding overcharging consumers in New York City, and it would not have undesirable consequences, such as harming third parties, the ISO said. 

“NYISO argues that although the correction may result in lower capacity prices in Load Zone J, which may be contrary to the economic interests of some market participants, no stakeholder has a legitimate interest in preventing an error from being corrected for that reason,” FERC said. “NYISO asserts that all market participants will benefit from capacity auction prices that accurately reflect NYISO’s methodology for computing transmission security limit floor values for LCRs.” 

The LCR is also the basis for several downstream processes related to the capacity market, such as the determination of capacity accreditation factors and the availability of capacity import rights, but NYISO said it did not need to fix those issues yet because the financial impacts of doing so would be limited. However, the ISO said it would continue to work with stakeholders to assess the feasibility, implications, timelines and required actions to pursue any corrective actions going forward. 

The Independent Power Producers of New York and New York City both said NYISO should work expeditiously to complete the assessment of how other downstream parts of the capacity market might be impacted.  

FERC found that the waiver request met its requirements, including solving the concrete problem of avoiding overcharging for capacity. 

While some parties argued for additional requirements that NYISO fully address the downstream impacts of its error, FERC said such arguments were beyond the scope of the proceeding. The commission encouraged NYISO to expeditiously complete its assessment of the error’s impact and continue working with stakeholders on a solution. 

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Wisconsin PSC: Missing Info in We Energies’ Oak Creek Coal-to-gas Plans

The Public Service Commission of Wisconsin said it’s missing several details from We Energies regarding its multiyear plan to substitute gas for coal at its Oak Creek Power Plant south of Milwaukee.  

In a May 3 letter, the commission said it and the Wisconsin Department of Natural Resources reviewed We Energies’ application for a certificate of public convenience and necessity to build the gas plant and deemed it incomplete. The PSC told the utility it could not make a decision and to re-file an application including the overlooked specifics (6630-CE-317). 

We Energies intends to retire two of its 60-year-old Oak Creek coal units this month and the remaining two units by December 2025. It has requested to replace the capacity on-site with $1.4 billion in five gas-fired combustion turbines that would generate up to 1.1 GW. The utility applied for the certificate at the beginning of April and expected to have commission approval this month.  

The Wisconsin PSC compiled a three-and-a-half-page list of missing or incomplete elements in the application. The agency asked for modeling data supporting the case for the plant, drawings of proposed and alternate layouts, an estimated maintenance schedule, a description of all major construction activities and a breakdown of capital costs. The commission asked We Energies to detail how hydrogen “may be used for any potential future fueling of the proposed combustion turbines.”  

The agency also zeroed in on how the plant could be affected if the utility’s proposed, 33-mile Rochester Lateral gas pipeline is rejected, and asked how the pipeline stands to affect the plant’s construction schedule. We Energies filed for permission to build the pipeline — which would supply firm natural gas service to Oak Creek — on the same day it requested commission approval to the build the plant.  

The PSC asked We Energies to calculate the amount of firm natural gas supply needed to run all five turbines continuously at maximum output and asked if its proposed upgrades to its natural gas infrastructure — alongside ANR Pipeline Co.’s planned capacity expansion in the area by late 2027 — would be enough to support those kinds of operations. It also asked how much a proposed, on-site liquified natural gas storage tank would hold and how long the tank could support the new turbines running at full speed.   

The commission said it wanted to know if We Energies anticipates or has factored in additional costs to convert the Oak Creek substation since the new gas plant must connect to the MISO system at different voltages than the existing coal plant. Transmission owner American Transmission Co. is phasing out its 230-kV system in the area and will use only 138-kV and 345-kV voltages, affecting Oak Creek’s point of interconnection.  

In February, FERC granted We Energies a departure from MISO’s interconnection rules so the replacement gas plant can connect to the system at a different voltage without the utility having to submit a fresh interconnection request with MISO. (See We Energies Secures FERC Permission to Switch Coal Interconnection with Gas Plant.)  

The PSC asked whether We Energies has contacted MISO to perform retirement studies to figure out if the system can operate reliably as the coal units cease production and after Oak Creek’s interconnection point is calibrated to different voltages. It said it wanted to know if powering down the four coal units can “proceed as planned without reliability concerns.” It also asked whether Oak Creek’s generator replacement studies consider only the two immediate coal unit retirements or all four of them.   

Finally, the PSC said We Energies submitted an incomplete construction-noise study with its application.  

In its application to build the plant, We Energies called Oak Creek’s shift to natural gas a “key component” in providing reliability amid its fleet transition, conforming to MISO’s stricter resource adequacy rules, meeting growing load and complying with proposed EPA requirements.  

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EPA Finalizes Methane Reporting Rule for Oil and Gas Industry

EPA issued a final rule May 6 meant to strengthen, expand and update methane emissions reporting requirements for oil and natural gas systems, as required by the Inflation Reduction Act. 

Oil and natural gas facilities are the largest industrial source of methane, which is a stronger greenhouse gas than carbon dioxide — though shorter lived — and estimated to be responsible for about a third of the increase in global average temperatures. 

The IRA’s Methane Emissions Reduction Program is meant to help states, industry and communities implement recently finalized standards under the Clean Air Act and slash emissions from the oil and gas sector. The Biden administration also is mobilizing $1 billion to accelerate the transition to no- and low-emitting oil and gas technologies as part of a broader effort to cut methane emissions. 

“EPA is applying the latest tools, cutting-edge technology and expertise to track and measure methane emissions from the oil and gas industry,” EPA Administrator Michael Regan said in a statement. “Together, a combination of strong standards, good monitoring and reporting, and historic investments to cut methane pollution will ensure the U.S. leads in the global transition to a clean energy economy.” 

EPA said studies have shown that actual emissions from the oil and gas industry are much greater than what they have reported to the agency. The new rule is meant to address that gap by making it easier to use satellite data to identify superemitters and quantify large emission events, and by requiring direct monitoring of key emission sources. 

EPA also is finalizing new methods allowing empirical data for quantifying emissions to be used. The changes are meant to improve transparency and give owners and operators more options to submit empirical data to show their efforts to cut methane emissions. 

The rule covers about 8,000 facilities around the U.S., which have to report their emissions data annually; EPA publishes the results every October. Owners and operators of oil and natural gas systems that emit 25,000 metric tons or more of equivalent carbon dioxide emissions annually are required to report their emissions. 

Aaron Padilla, vice president of corporate policy for the American Petroleum Institute, said in a statement that the final rule raises serious concerns, including the use of “flawed methodologies” that could lead to inaccurate reporting of higher GHG emissions. 

“We are reviewing the final rule and will work with Congress and the administration as we continue to reduce GHG emissions while producing the energy the world needs,” he said. 

The Environmental Defense Fund, which launched its own satellite earlier this year to track methane emissions, welcomed the new rules. 

“By directing EPA to update and strengthen methane emissions reporting, Congress recognized the vital importance of measurement-based, accurate and scientifically robust data to establish the true volume of pollution created by the oil and gas industry,” EDF Senior Scientist Daniel Zavala-Araiza said in a statement. “Updated methane reporting, along with continued integration of new measurement data, will allow us to better understand emission sources and mitigation opportunities and track changes in emissions over time.” 

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Members Vote Against Granting PJM Filing Rights over Planning

BALTIMORE, Md. — The PJM Members Committee on May 6 rejected endorsement of revisions to the RTO’s Operating Agreement and tariff shifting filing rights over the Regional Transmission Expansion Plan (RTEP) from the committee to the Board of Managers. 

The language received 25% sector-weighted support during PJM’s Annual Meeting, held this year at the Baltimore Marriott Waterfront hotel. 

The proposal was brought to the MC by the PJM Board of Managers in response to similar revisions to the Consolidated Transmission Owners Agreement (CTOA) brought to the Transmission Owners Agreement-Administrative Committee (TOA-AC). The TOA-AC also is set to consider revising the CTOA on May 14. Should the CTOA be modified, modifications to the PJM OA and Tariff would be necessary to avoid inconsistency.

The vote does not necessarily prohibit the board from unilaterally filing a proposal with FERC. PJM Director of Stakeholder Affairs Dave Anders said the board sought the input of stakeholders on the changes prior to considering whether to agree to any CTOA amendments that the TOA-AC may request.

During the April 25 Markets and Reliability Committee meeting, PJM General Counsel Chris O’Hara said the board has not ruled out making a Federal Power Act Section 206 filing asking FERC to grant it filing rights over the RTEP protocol if TOA-AC approves the CTOA revisions and the MC does not endorse the companion OA and Tariff revisions.

. At the Annual Meeting, board Chair Mark Takahashi stressed that no decisions had been made and that the board values the stakeholder process. There may be some cases, however, where the membership reaches a stalemate and the process cannot yield a solution to an issue that needs resolving, he said. 

Several stakeholders argued they had only weeks to consider the changes, leaving insufficient time to vet the language for unintended consequences or to provide thoughtful comments. 

Paul Sotkiewicz, president of E-cubed Policy Associates, said transferring the planning to the Tariff from the OA, in the context of the planning reforms in the table, would lead back to integrated resource plans. 

Susan Bruce, of the PJM Industrial Customers Coalition, said the key difference with the RTO holding filing rights is that overriding an MC vote currently requires a filing under FPA Section 206, which must demonstrate that the existing governing document language is unjust and unreasonable. 

“We strongly believe in the stakeholder process. The PJM stakeholder process has been important in balancing parties’ rights in this industry that has gone through a lot of transitions,” she said, adding that stakeholders have not had adequate time to think through the proposal. 

LS Power’s Sharon Segner argued that any MC votes to amend the OA must immediately result in a FERC filing, but the drafted CTOA language includes a mediation process for any instances where a TO objects to an MC vote that it feels is contrary to the agreement. She said the interactions between that provision and the proposed OA and tariff language are not understood. 

The status quo governing document language strikes a balance between granting TOs filing authority over local planning decisions, while PJM membership holds filing authority over regional planning. 

Exelon’s Alex Stern said the PJM Members Committee is not a FERC jurisdictional public utility.  It is a body created for consultation and does not have regional planning authority — that burden lies with PJM, which should hold final say over planning decisions. Stern asserted that “the Planning Protocol was directed to be placed in the OA by FERC nearly two decades ago to afford PJM independence. Unfortunately, as things have evolved, that intention has been thwarted to the point that people now actually incorrectly believe the Members Committee and not PJM has the regional planning authority.”

He said TOs, as PJM members, also are giving up stakeholder process veto rights over the planning protocols, but supporters of the CTOA revisions believe changes are needed to ensure reliability through the clean energy transition and to meet rising load, noting the growing reliability challenges facing PJM, highlighted by last week’s announcement that the summer outlook PJM presented to the Operating Committee on May 2 stated there’s a smaller generation pool available this summer than past years while forecast peak loads are increasing. (See related story, “PJM Confident on Summer Reserves; Stakeholders Concerned About Long Term,” PJM Operating Committee Briefs: May 2, 2024.) 

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PJM PC/TEAC Briefs: April 30, 2024

Planning Committee

Stakeholders Discuss Change to CIR Transfer Issue Charge

The East Kentucky Power Cooperative presented potential revisions to the process for transferring capacity interconnection rights (CIRs) from a retiring generator to a replacement resource. 

The changes would allow for solutions to include CIR transfers to planned resources interconnecting at the same substation as the deactivating unit, but on a different breaker. Both sets of language would preclude proposals contemplating shifting CIRs to a resource connecting to an entirely different substation. 

During the April 2 PC meeting, EKPC Vice President of Federal and RTO Regulatory Affairs Denise Foster Cronin said package formation at the Interconnection Process Subcommittee revealed the issue charge would prevent solutions sought by some stakeholders to allow CIRs to be transferred to a new resource interconnecting on a different breaker, but which otherwise are electrically equivalent. (See “Stakeholders Discuss Expanding CIR Transfer Issue Charge,” PJM PC/TEAC Briefs: April 2, 2024.) 

Exelon Director of RTO Relations Alex Stern suggested modifying the proposed revisions to require that solutions allow only CIR transfers to generators interconnecting at the same or lower voltage as the original resource. Stern argued that increasing the voltage would be more likely to impose additional costs as well as implications to service to others that would compromise the clean CIR transfer the issue charge intended to explore. The suggestion was not accepted to provide more time for the package sponsors, EKPC and Elevate Renewables, to consider the changes. 

First Read on CIFP Manual Revisions

PJM presented a set of manual revisions to codify changes to capacity accreditation, reliability risk modeling and procurement targets FERC approved in January following PJM’s Critical Issue Fast Path (CIFP) process last year. (See FERC Approves 1st PJM Proposal out of CIFP.) 

Manuals 20, 21 and 21A would be replaced with new Manuals 20A and 21B — which respectively detail resource adequacy analysis and the determination of generating capability. Manual 14B, which pertains to the regional transmission planning process, would see changes to its load deliverability analysis and the capacity emergency transfer objective (CETO) and capacity emergency transfer limit (CETL) analyses. 

PJM plans to ask the PC to vote on endorsing the manual revisions during its June 4 meeting. The Market Implementation Committee endorsed related revisions to Manual 18, which relates to the capacity market, on May 1. If endorsed, the manual revisions would be effective for the 2025/26 delivery year. 

Transmission Expansion Advisory Committee

PJM Updates RTEP Timeline

PJM intends to open two competitive Regional Transmission Expansion Plan (RTEP) windows in July to solicit proposals to resolve transmission violations and interconnect 3.5 GW of wind generation planned off the New Jersey shoreline. (See “PJM Preparing 2 Competitive Transmission Windows in July,” PJM PC/TEAC Briefs: April 2, 2024.) 

PJM’s Sami Abdulsalam presented the Transmission Expansion Advisory Committee with a plan to use an eight-year horizon when identifying grid upgrades necessary under New Jersey’s second State Agreement Approach (SAA), under which the state agreed to cover the cost of transmission necessary to meet its policy goal of developing 3.5 GW of offshore wind. 

The longer window allows the RTEP analysis to capture how load growth, generation deactivations and the first round of SAA transmission — which aims to facilitate the interconnection of 7.5 GW of offshore wind in New Jersey — may interact with transmission needs identified, Abdulsalam said. 

The eight-year window also will identify any reliability needs and could lead to multi-driver projects that share reliability and facilitate offshore wind interconnection in New Jersey.  

PJM also aims to open the first standard reliability-focused five-year window of the 2024 RTEP in July. Abdulsalam said the window likely will be open for 60 days. Vice President of Planning Paul McGlynn told RTO Insider that more detail about needs identified in the window likely will be presented in June or July. 

Scope Change to 2022 Window 3 RTEP Adds $19.5 Million

PJM has expanded the scope of a component of the 2022 RTEP Window 3 to upgrade an existing 230-kV line to 500-kV for an estimated $19.5 million. 

The original project scope was to add a 500-kV line parallel to the existing Otter Creek-Conastone 230-kV line. Abdulsalam said dialogue between PJM and PPL suggested there could be substantial benefits to upgrading the existing line as part of the project. 

Upgrading the line as part of the 2022 RTEP could limit construction along the corridor and add scalability to a vital corridor for moving power between northern and southern PJM regions. 

The project is one component of a larger $5 billion transmission expansion the PJM Board of Managers approved in December 2023 to address concentrated load growth in northern Virginia and about 11 GW of deactivating generation, most notably the Brandon Shores plant and the Wagner Generating Station outside Baltimore. 

Supplemental Projects

FirstEnergy proposed a $35 million project to upgrade its South Reading 230-kV substation in the Med-Ed transmission zone to mitigate the risk of multiple breakers or a bus fault causing the entire facility to go offline. The proposal would reconfigure the substation to a double-breaker, double-bus configuration; replace the bus conductor; install new circuit breakers; and build a new control house. The work would increase the ratings of the 230-kV lines between South Reading and the Boonetown, Lauschtown and Berks substations. 

The project is in the engineering phase, with a project in-service date of Dec. 31, 2026. 

The utility also proposed rebuilding its gas-insulated 230-kV Smithburg substation in the JCPL transmission zone due to the need for specialized parts, poor performance and its age at over 40 years old. The $30.2 million project would reconfigure the substation to be open-air, along with upgrading terminal equipment, retiring the Smithburg-Larrabee and revising relays at the Larrabee, East Windsor, New Prospect Road and Manalapan facilities. 

The project is in the conceptual phase, with a possible in-service date in June 2027. 

FirstEnergy also presented several proposed projects to replace transformers across its facilities. A $56.4 million project would replace three 500/138-kV transformers at its Belmont substation in the APS transmission zone. The utility said the units are approaching their end of life and are experiencing degradation challenged by obsolete replacement parts. The replacements would be staggered to go in service between June 2027 and December 2029. 

Two separate projects also would replace 230/69-kV transformers at the South Reading substation, due to increased gas levels and their age. The projects, which are in the engineering phase, would total $17.6 million, with completion targeted in June and December 2025. 

In the Penelec zone, FirstEnergy proposed replacing a 230/115-kV transformer at its Shawville substation due to age, maintenance issues and nitrogen leaks. The utility also discussed replacing a 345/230-kV transformer at the Homer City substation as it approaches its end of life and parts have become obsolete. The projects are estimated to cost $17.6 million. 

Exelon presented a $35 million project to install seven new 345-kV circuit breakers at its Libertyville substation in the ComEd zone, as well as replace two deteriorating oil circuit breakers with SF6 based units. 

Dominion presented a problem statement for possible reliability violations along the transmission corridor between the Possum Point and Fredericksburg substations. More than a dozen substations are planned in the region to serve growing data center load, which could strain existing transmission even with four ongoing projects to upgrade the corridor to hold two 230-kV lines, the utility said. 

Projections of the load interconnecting on the 13 new substations suggest consumption could increase by more than 1,700 MW by 2029 and by more than 3,000 by 2032. Dominion said load is increasing at a similar pace along the corridor to the south of Fredericksburg, with 14 new substations along that segment estimated to have 2,000 MW of new load by 2029 and an additional GW by 2032. 

Ensuring adequate transmission in place would require either new “diverse transmission sources” or additional reconfiguring of the two 230-kV lines to allow additional lines to be installed, which Dominion said may result in increased outage times, higher costs and delays to consumer in-service dates. 

Dominion proposed rebuilding its 10.6-mile Harrisonburg-Grottoes 230-kV line as it approaches the upper end of its expected lifespan. Most of the line was built in 1970 with wood structures, which would be replaced with steel at an estimated cost of $28 million. The project is in the conceptual phase, with a possible in-service date in December 2027. 

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PJM MIC Briefs: May 1, 2024

Stakeholders Endorse Manual Revisions to Implement CIFP Changes to Capacity Market

The Market Implementation Committee endorsed by acclamation a rewrite of Manual 18 to implement market redesigns drafted through the Critical Issue Fast Path (CIFP) process last year and approved by FERC in January. (See FERC Approves 1st PJM Proposal out of CIFP.)  

If endorsed by the Markets and Reliability Committee, the revisions would expand the use of effective load carrying capability (ELCC) analysis for accrediting all generation types, require that planned resources notify PJM of their intent to participate in a Base Residual Auction (BRA) at least 90 days in advance and change how generation unforced capacity (UCAP) values are calculated. 

The Planning Committee endorsed related revisions to Manuals 20, 21 and 21A on April 30 to reflect the risk modeling and accreditation changes the commission approved. 

The revisions to Manual 18 would shift the calculation of the maximum annual nonperformance penalties generators face to be based on the net cost of new entry (CONE) — effectively decreasing the penalty over the current use of auction clearing prices. 

First Read on Proposed Demand Response Energy Market Parameters

PJM’s Pete Langbein presented a proposal to add two energy market parameters for demand response resources that would allow them to specify a maximum run time and a minimum “cooldown” period after being dispatched before the resource can be committed again. 

Langbein said PJM plans to ask the committee to endorse the revisions June 5 with the aim of filing the proposal at FERC in October. He said the filing likely would request a nine-month implementation period due to the complexity of changing the market clearing engine and to allow testing of the changes. 

Langbein said there are differences between a resource saying it’s not economical to operate under certain conditions and being able to respond to a capacity call. 

“They’re not saying they can’t respond; they’re saying they don’t want to respond because it’s not economical,” he said. 

Update Re-evaluation of CONE Inputs

PJM plans a June 5 presentation to discuss analysis by the Brattle Group on whether the CONE values produced by the most recent quadrennial review remain accurate or should be updated to reflect rising interest and construction costs. (See “PJM Re-evaluating CONE Inputs,” PJM MRC Briefs: April 25, 2024.) 

Skyler Marzewski, PJM | © RTO Insider LLC

FERC approved the quadrennial review in February 2023, accepting a shift to a forward-looking energy and ancillary (EAS) offset and a combined cycle reference resource, rather than the previous combustion turbine. (See FERC Approves PJM Quadrennial Review.) 

PJM’s Skyler Marzewski said a quick-fix proposal revising the inputs to the CONE calculation may be included in the June presentation, with the aim of submitting a FERC filing in August or September. Any changes to CONE values would be effective for the 2027/28 BRA. The quick-fix process allows for an issue charge and proposal to be voted on concurrently. 

PJM’s Pat Bruno said Brattle’s analysis includes whether there should be more regular revision of the CONE inputs, possibly through escalation factors. 

Stakeholders Regroup on Energy Efficiency Rules After MRC Rejection of Proposals

Proposals rewriting how the capacity contributions of energy efficiency resources are measured and verified were brought back to the drawing board after the MRC rejected four packages in March. (See “Stakeholders Reject Changes to EE Measurement, Verification,” PJM MRC/MC Briefs: March 20, 2024.) 

PJM questioned the value EE provides, with Langbein stating he has yet to see a case made that capacity market revenues are incentivizing the purchase of devices more efficient than what consumers otherwise would have bought. 

“They shouldn’t be able to claim things that are naturally going to occur … if I’m making a decision to purchase a high-efficiency air conditioner, an EE provider shouldn’t be able to claim that unless they can prove” that they incentivized the purchasing of that unit over a less efficient product, Langbein said. 

Luke Fishback, of Affirmed Energy, said the purpose of EE is to find the most economically efficient way of pricing a guaranteed reduction in consumption over PJM’s load forecast. 

Several items were added to the solution matrix, including requirements for when EE providers may need contracts with each of the end-use customers participating in EE programs. PJM also modified an option previously part of its package, which would require end-use customer data be provided to PJM, to only require that data be provided to the RTO upon request. 

The stakeholder process is focused on developing package components, which could be used to develop new proposals for the committee to consider later. 

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PJM Operating Committee Briefs: May 2, 2024

PJM Confident on Summer Reserves; Stakeholders Concerned About Long Term

PJM presented its 2024 summer study to the Operating Committee on May 2, saying preliminary figures show the region has adequate reserves to maintain reliability even as reserve margins tighten relative to recent years. 

The summer case overview has a reserve margin of 2.8 GW above the 168.2-GW operating reserve requirement. PJM will be going into the summer with a fleetwide installed capacity (ICAP) of 182.5 GW and 7.5 GW of load management, which is offset by discrete generator outages expected to be about 13.9 GW and a net interchange reducing capacity available by an additional 5 GW based on historical trends. 

In an announcement of the study’s findings, PJM CEO Manu Asthana said they underscore resource adequacy concerns the RTO has been sounding since it released its “4Rs” research paper in February 2023. 

“We plan throughout the year to make sure we have enough resources to serve load at the hottest time of the year. But we are concerned that new generation is not coming online fast enough to replace retiring resources, and that subsequent years may be more challenging,” he said. 

The reserve margin tightens under some scenarios PJM runs on top of the summer case, with an extreme generation event possibly reducing available generation by 20 GW and resulting in a margin 3.2 GW below the operating reserve requirement. Low solar and no wind could result in a 2.5-GW margin, and the largest gas-electric contingency also falls 2 GW under the reserve requirement. 

PJM’s Robert Dropkin said the scenarios pair the “extreme” 90/10 load forecast with unlikely generation events. 

“The system is tighter than it has been in past years, [but] we are still able to control some of the issues we’ve seen,” he said. 

The 2023 summer outlook found that the largest gas-electric contingency carried a 4.1-GW reserve margin, while a low-solar-and-no-wind event would have a 3.4-GW cushion. 

Exelon Director of RTO Relations Alex Stern said he views the slimmer margins as a warning sign of future reliability issues. 

“I know we’re saying ‘no reliability issues identified’ in the peak load analysis, but this just seems to be another area of concern about the reliability of the system [and] resource adequacy,” he said. “I kind of feel like it’s another data point in the direction that we’re heading into some problems.” 

The announcement notes that PJM’s fleetwide ICAP fell by 4 GW over what was available last summer, while the forecast peak load increased to 151 GW, compared to 147 GW last year. 

Aftab Khan, PJM executive vice president of operations, planning and security, said high temperatures forecast by the National Weather Service for this summer further complicates the outlook. 

“With increasingly unpredictable weather patterns, we need to also prepare for more extreme weather conditions. We will continue to work with our utility partners and stakeholders to refine our planning, analysis and communications of the risks presented by any challenging weather patterns this summer,” he said in the announcement. 

Security Update

PJM’s Jim Gluck encouraged stakeholders to be cautious about data shared with outside companies and consultants they work with, as attacks on software providers that have access to sensitive data could create vulnerabilities for companies that have not been breached themselves. 

The proliferation of artificial intelligence capable of mimicking the writing and speech of individuals also could be used in social engineering attacks by impersonating employees of a company. 

Operating Metrics

PJM presented its operating metrics for April, which saw a peak hourly forecast error of 1.26%. The month saw two spin events and two shared reserve events. 

Special OC on Black Start RFP

The OC convened a special session to discuss an incremental request for proposals that PJM is conducting to procure additional fuel-assured black start resources.  

PJM’s Ray Lee told the committee some transmission zones did not meet the minimum requirement of one fuel-assured resource in the 2023 RTO-wide black start RFP. The 2023 solicitation was the first under rules stakeholders adopted in 2022 requiring at least one fuel-assured resource in each transmission zone. (See Stakeholders Endorse PJM’s Black Start Fuel Reqs Proposal.) 

The RTO posted the RFP on April 29 and submissions open for Level 1 proposals on May 28, with the goal of awarding assignments to resources between August and December. The solicitation is for service starting in January 2027. 

PJM encouraged resources that may not meet the fuel assurance qualifications to nonetheless submit offers, as one of the ways a transmission owner can meet the requirements is to have two black start units that are connected to different interstate gas pipelines. The preferred way is for a generator to have on-site storage, though there are several ways a generator can qualify. 

David Kimmel, PJM senior engineer, said staff are planning to bring a manual revision to stakeholders to create exceptions to the requirement that generators with on-site storage hold at least 16 hours worth of fuel. The proposal would exempt generators if they consumed a portion of that fuel to respond to a capacity call or because of needing to drain tanks for regulatory inspections. 

The proposal likely would not have a hard requirement for when storage would need to be replenished, Kimmel said, with PJM instead leaning toward giving flexibility depending on the generator’s circumstances, but it likely would be within a few days of consumption. 

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Will Final Rules on EV Tax Credits Help or Hurt US Market Growth?

The most pressing questions about the final rules on the Inflation Reduction Act’s electric vehicle (EV) tax credits issued May 3 should not be about their nitpicking complexity or whether they comply with the letter of the law in every single detail, but if and how they could affect EV sales and market growth in the United States. 

The Internal Revenue Service issued its final rules on which vehicles are eligible for the $7,500 tax credit for new EVs — including the law’s much-debated domestic content provisions — while the Department of Energy issued its final rule on “foreign entities of concern” (FEOCs), another key component of eligibility requirements. 

The IRS has been working on the rules since December of 2022, when it issued its first policy paper and notice of intent for proposed rulemaking outlining its approach to the EV tax credit provisions — including the basic eligibility requirements originally drafted by Sen. Joe Manchin (D-W.Va.). 

The key change in the final rules is a two-year phase-in for certain elements of the domestic content requirements, allowing more time for the U.S. to stand up its own supply chains for the critical minerals and other components used in EV batteries, which in turn could increase the number of EV models qualifying for the credit.  

Beginning Jan. 1, 2027, automakers will be required to perform rigorous upfront tracking and certification of domestic content in their supply chains, but until then, will be able to continue using a less rigorous certification process established in the proposed rules. 

The final rule also adds graphite used in battery anode materials to a short list of other critical materials that are used in EV batteries in such small amounts that they are classified, at present, as “impracticable to trace” — and therefore exempt from the domestic content requirements at least until Jan. 1, 2027.  

Manchin immediately blasted the Biden administration for creating “loopholes” in the law, which could allow China to continue dominating the EV battery market rather than supporting the domestic supply chains, which he intended the IRA to create. 

“The entire point of the Inflation Reduction Act was to provide American businesses the incentives they need to bring our energy and manufacturing supply chains back to the U.S., reduce our dependence on foreign adversaries and create good-paying American jobs,” he said in an email statement. “Instead of embracing those opportunities to benefit our country, the administration is so desperate for Chinese EV components that they are blatantly breaking the law by implementing a bill that they did not pass and ignoring what Congress agreed upon at the expense of American workers and taxpayers.” 

But John Bozzella, president and CEO of the Alliance for Automotive Innovation (AAI), an industry advocacy group, framed the final rules as “good sense for investment, job creation and consumer EV adoption … [and] providing some temporary flexibility in terms of where the critical minerals in EV batteries can be sourced.  

“The EV transition requires nothing short of a complete transformation of the U.S. industrial base. That’s a monumental task that won’t ― and can’t ― happen overnight,” Bozzella said in a statement on the AAI website. 

“Imagine an EV that complied with all IRA eligibility requirements but is kicked out of the program because of a trace amount of a critical mineral from an FEOC,” he said. “That makes no sense — especially when you consider the massive investments automakers and suppliers are making in domestic EV manufacturing.” 

The Basics

Despite criticism from Manchin and other stakeholders, the IRS final rule maintains the basic eligibility requirements laid out in the law and in the agency’s previous iterations of different provisions of the rule issued in April, October and December of 2023. 

To qualify for the tax credits, the final assembly of an EV must occur in North America, the retail price must not exceed $55,000 for a sedan or $80,000 for an SUV or light-duty pickup, and the weight must not exceed 14,000 pounds. Prospective buyers cannot earn more than $150,000 for those filing their taxes as individuals, $225,000 for single heads of house and $300,000 for couples filing jointly.  

Whether any one vehicle qualifies for a partial $3,750 credit or full $7,500 credit depends on its domestic content. For the full credit, a vehicle must meet gradually increasing requirements for both critical mineral content in its battery and other battery components. Meeting only one of the domestic content requirements qualifies a vehicle for the partial credit.  

For example, the mandated percentage of the value of critical minerals in an EV battery that are domestically sourced and processed began at 40% in 2023, is 50% this year and will increase yearly by 10% until it reaches 80% in 2027 and beyond. 

The FEOC rules are similarly straightforward: Beginning this year, any EV with critical minerals or other battery components either sourced or processed by a “covered nation” ― China, Russia, North Korea or Iran ― or other foreign entity of concern will not be eligible for the tax credit.  

The rule also spells out a list of conditions under which a company can be classified as an FEOC, such as whether it is in a covered nation or whether a covered nation has a 25% controlling interest, via seats on a board or equity interest.  

But the exact calculus between these eligibility requirements, the time frames for domestic supply chain buildout and auto industry confidence in consumer demand remains uncertain. 

The AAI estimates that electric vehicle and battery manufacturers have invested $125 billion to stand up U.S. supply chains since 2017, while the administration pegs the figure at $173 billion in new investments announced since Biden was elected.  

According to DOE, average monthly sales of EVs doubled from about 50,000 per month in 2021 to more than 100,000 in 2023. Total EV sales in 2023 topped a record-breaking 1.6 million.  

Bumps in the Road

But sales have not increased as fast as automakers expected, and U.S. market leaders, including GM and Ford, have scaled back their investments and time frames for ramping up EV production, shifting instead toward a focus on plug-in hybrids. 

According to Kelley Blue Book, 268,909 EVs were sold in the U.S. in the first quarter of 2024, a modest year-over-year increase of 2.6% compared to the 46.4% jump between the first quarters of 2022 and 2023.  

But Kelley’s analysis suggests that “the slow growth may be a sign that EVs are almost mainstream cars in parts of the country. Segment growth typically slows as volume increases. 

“Consumers follow a predictable curve as they adopt new technologies. There’s almost always an initial surge as early adopters excitedly jump in. Then sales growth slows as more skeptical consumers take a look at the technology and have to be convinced.” 

The role of EV tax credits in consumer decisions on going electric also may vary. Kelley’s analysis points to price as a major factor, and the IRS rule allows for direct pay of the tax credit at point of sale for eligible vehicles, which could make EVs more affordable and attractive. 

Tax credits have been paid at point of sale for more than 100,000 vehicles so far this year, according to the Treasury Department.  

AAI estimates that the U.S. EV market now offers consumers about 114 models, but only 22 are eligible for a partial or full tax credit: nine plug-in hybrids and 13 full electric models.  

The catch here is that automakers in most cases are entering the EV market with more expensive SUV and light pickup models. DOE’s list of EVs and plug-in hybrids eligible for IRA tax credits in 2024 include only two classified as sedans: the Nissan Leaf and Tesla’s Model 3.  

One of the more affordable models on the market, Chevrolet’s popular Bolt, was discontinued in December of 2023. 

The slow rollout of a national network of public chargers ― both Level 2s and DC fast chargers ― also has frustrated consumer and industry expectations. The Infrastructure Investment and Jobs Act’s $5 billion National Electric Vehicle Infrastructure (NEVI) program has, to date, installed only eight of the 500,000 fast chargers President Joe Biden wants on the nation’s highways by 2030. 

On April 23, Vermont’s first NEVI charger ― with four ports, located in the town of Bradford ― joins the handful of others now online in Hawaii, Maine, New York, Ohio and Pennsylvania. 

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CAISO’s Capacity Procurement Mechanism Inefficient, Stakeholders Say

Lack of visibility into the contract and availability status of the fleet is causing “inefficiencies” in CAISO’s capacity procurement mechanism (CPM) process, said staff and stakeholders in a two-day Resource Adequacy Modeling and Design Working Group on April 29 and 30. 

“For us to be able to effectively do a CPM designation and backstop, we really need to look into what RA is offered to us,” said Abdul Mohammed-Ali, operations engineering manager at CAISO. 

In the past, CAISO viewed non-RA shown capacity as available in the market and therefore factored into its CPM decision-making, said Peter Griffes, chief of comprehensive market design at Pacific Gas and Electric. But because of retail structure changes, there isn’t the same assurance of available capacity. 

CAISO hasn’t decided whether it should evaluate non-RA resources when determining RA capacity, but without knowledge of what is shown, stakeholders expressed confusion surrounding how and when CAISO decides to CPM and feared that a lack of clarity on availability could lead to unnecessary backstop. 

“We think it’s important that [CAISO] maintain some levels of discretion and make the right operating decisions to ensure that it has the capacity it needs to support reliability of the system but also does not engage in unneeded backstop procurement that would ultimately increase the cost for ratepayers,” said Tony Zimmer, assistant general manager of power management at the Northern California Power Agency. 

The ISO bases CPM decision-making on shown RA capacity, or resources that appear on supply plans, and Competitive Solicitation Process (CSP) offers, which are voluntary bids into the market from scheduling coordinators up to the soft offer cap. CAISO recently received FERC approval to increase the cap from $6.31/kW-month to $7.34. (See CAISO Receives FERC Approval to Increase Soft Offer Cap.) 

But since 2020, CSP offers have “dried up,” especially in the summer months, said Mohammed-Ali. Prior to the increase, the ISO stated in its RA Discussion Paper that the cap is not cost competitive with bilateral market prices, potentially causing the lack of CSP offers. 

“Because of these market dynamics, the ISO hypothesizes that the lack of offers in the CSPs is driven by a combination of most capacity being under contract and sellers of any available capacity having alternatives well above our soft offer cap,” the discussion paper reads. “If the ISO is unable to procure capacity to CPM, the CAISO BA has the direct risk of not having sufficient capacity to reliably operate the grid.” 

“That’s one of the main challenges, because now, even if we decided to backstop, this is our pool, and our pool is dry,” Mohammed-Ali said. 

In its request to FERC to increase the cap, CAISO argued that it would better reflect inflation and higher bilateral capacity prices. 

Another challenge lies in CAISO’s concern that scheduling coordinators may be holding back capacity for outage substitution, which could impact the efficiency of CPM decision-making. But without visibility into the non-RA fleet, it’s unclear. Load-serving entities may choose not to show resources because of the consequences associated with being counted as RA, including being subject to the Resource Adequacy Availability Incentive Mechanism test, must-offer obligations, substitution rules and bid insertion rules. 

“If there’s resources that are being held by people for substitution while others are unable to meet RA compliance requirements, and the ISO is unable to meet CPM, we need to understand why people are holding those types of quantities and causing that type of difficulty,” said Eric Little, director of regulatory affairs at CalCCA. “I think we ought to do a better job examining the data and … making publicly available the information so that everybody can see exactly what’s going on in terms of capacity space.” 

Solutions

The ISO can better utilize available capacity if it considers resources scheduled to receive a commercial operation date in its CPM decision-making, Perry Servedio, a consultant to the California Energy Storage Alliance, said in a presentation to CAISO. 

“If you’re having a lack of offers, why not do something in which you can have more RA available to you even with that lack of offers?” Servedio said. “If folks can show resources that are planning to come online, then that gives you visibility as well, and that would be a showing that’s contracted, and they want to rely on it for RA, but it’s not yet online.”  

The timeline is set so that, 30 days (T-30) after RA and supply plans are due, CAISO reviews data and decides whether it needs to backstop. But there is a lot of capacity that comes online between T-30 and T-zero that, because of the compliance timeline, can’t be considered for RA, Servedio said. 

“What I’m really driving at here is there’s all these resources that are contracted by loads to provide RA that are not able to be RA in the compliance month due simply to this timeline,” Servedio said. 

Nuo Tang, director of asset management at Middle River Power, agreed with Servedio’s emphasis on “frontstop” rather than backstop. 

“While we’re focused a lot on backstop procurement, I think we’re missing a big point of what should the ISO do to ensure there’s good incentives for frontstop procurement?” he said. 

Also at issue was whether to rely on the ISO’s default planning reserve margin (PRM) and 1-in-10 loss-of-load expectation (LOLE) to inform whether to backstop. Servedio suggested the ISO complete an “LOLE study” to determine reliability and better inform CPM decisions. Tang supported the need for a study and suggested CAISO give information to local regulatory authorities regarding what PRM is needed to prevent unnecessary backstop. 

But some stakeholders said CAISO shouldn’t determine the LOLE and reliability standards. 

“I fundamentally disagree with the notion that the ISO ought to be responsible for maintaining a 1-in-10 LOLE in the RA program,” Little said. “What we really need is the state looking at how it’s going to meet its reliability needs, which it should be doing through [integrated resource planning] and through RA and making sure those resources are available.” 

Consensus held that without visibility into CAISO’s full fleet, none of the other issues can be resolved. 

“Until we can solve these types of problems to understand where the capacity is and what’s preventing people from getting it, I don’t know that the ISO’s backstop process is going to be any more or less successful than anybody else out there right now,” Little said.