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November 14, 2024

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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. 

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SPP’s Stakeholder Process Attracts Markets+ Participants

TEMPE, Ariz. — While other Western Interconnection entities have spent their time recently filing comments on the SPP Markets+ tariff or committing to CAISO’s competing Extended Day-Ahead Market (EDAM), participants in SPP’s day-ahead proposal gathered in the Desert Southwest on April 30 for a healthy dose of the RTO’s stakeholder process. 

SPP has long prided itself on that process, which seeks membership’s consensus before any consideration for approval. Staff will tell you stakeholder-driven is not just a slogan, but reality. 

“Our specialty has always been in the stakeholder process. By bringing a lot of those best practices from our experiences and expertise in the East to the West, we’ve shaped it to help facilitate progress with the stakeholders here,” said Carrie Simpson, SPP’s Denver-based director of seams and western services. 

Shielded from Tempe’s bright sun and springtime heat by Salt River Project’s cavernous PERA Training & Conference Center, attendees dug into how they can submit tariff and governing revision modifications and interact with SPP staff. 

Senior market analyst Kristen Darden detailed the background, forms, structure and steps within the Markets+ revision request (MRR) process. Modeled after SPP’s RTO process, it facilitates stakeholder input and discussion by providing a transparent method for stakeholders and staff to recommend additions, deletions or changes to Markets+’ governing language.  

MRRs will be submitted through SPP’s Request Management System, an online platform that hosts the revision request process and responds to general questions, inquiries and requests. It also contains a knowledge base that can be used for FAQs.  

Once MRRs are posted to SPP’s website, they are open to comments. 

“I get really excited about our program,” Darden said. “I think it’s a great feature that we have. It shows we are stakeholder driven, we are considered public or transparent with everything that we do.” 

“I think they have embraced it, and it wouldn’t be successful without them embracing it and digging into it and participating,” Simpson said. “We’ve got diverse parties, different sectors, different regions of the West, and I absolutely think that’s been a part of the success of Markets+.” 

As if to drive the point home, SPP staff agreed with the Markets+ Participants Executive Committee (MPEC) that more education and input is needed on managing transactions across the market’s seams with EDAM and other balancing authority areas. Of course, SPP has deep experience in this area, given its seams with MISO. 

“It’s not a secret to anyone that the biggest scenario around objection to Markets+ is the seam,” said MPEC Chair Laura Trolese, with The Energy Authority. “I think starting to work through where the tension points are and what we can do to reduce transactional friction, I think would behoove us to be doing that work earlier rather than waiting till the end of the year.” 

“As staff, we hear loud and clear that we want to figure this out,” Simpson said. “I think there’s still just confusion on how it works if we do nothing, and so I think starting there can help people identify what friction exists and what friction does not exist. It’s a very important issue to address, and so I think we let that [stakeholder] process play out.” 

For the time being, “transactional friction” will go into the parking lot of items to be addressed further, but with a high priority. 

MSC Concerns on Tariff

Arizona Corporation Commissioner Nick Myers, incoming chair of the Markets+ State Committee (MSC), said that while the “industry” has said the tariff is good to file at FERC, some state regulators are concerned about market participants opting-out transmission capability from the market. 

“Some states have said they see that as a dealbreaker,” he said. “We’re still trying to strive for some consensus on that.” 

In comments filed at FERC, the MSC said some members have “strong concerns about the lack of guardrails around the monthly opt-out provision.” The tariff allows market participants to opt out with only 15 days’ notice. (ER24-1658). 

“It is critical to specify these reasons to safeguard against potential market manipulation,” the committee wrote. “It is unclear to the MSC how this option will operate in the context of reliance on the [Western Resource Adequacy Program]’s transmission requirements to ensure resource sufficiency in the day-ahead and real-time markets.” 

The Markets+ tariff requires its participants to also take part in the WRAP. That integration was cited by Bonneville Power Administration staff in their recommendation that the federal power marketing administration choose the SPP-run market over CAISO’s. (See BPA Staff Recommends Markets+ over EDAM.)  

“[It’s] about what constitutes the reasoning behind opting out,” Myers said. “There could be situations where that transmission is needed for other parties, and now there could be market advantages to an entity pulling out some transmission for no other reason than their own market advantage. There needs to be bounds around when that’s allowed to happen.” 

SPP said it “fully expects” the tariffs of participating Markets+ transmission providers and balancing authorities to have more details on opt-outs and promised to provide further details on the provision. 

“More transmission is better than less,” SPP attorney Chris Nolen said. “The opt-out gives us the ability to have transmission participate in the market. [Some entities] may have seasonal limitations or other things that absent some ability to opt out and we might not have access to that transmission at all.” 

Alluding to temperatures that would hit 96 degrees Fahrenheit during the meeting, Myers told MPEC attendees to count their blessings. “You guys are lucky it still hasn’t hit 100 degrees yet here in Arizona,” he said. 

Myers and Vice Chair John Hammond, with the Idaho Public Utilities Commission, are replacing Colorado’s Eric Blank and Oregon’s Letha Tawney, respectively.  

The MSC comprises regulators from Arizona, California, Colorado, Idaho, Montana, Nebraska, Nevada, New Mexico, Oregon, South Dakota, Utah, Washington and Wyoming. 

APS’ Walter Joins MPEC Leadership

New MPEC Vice Chair Kent Walter, Arizona Public Service | © RTO Insider LLC

The MPEC approved Arizona Public Service’s Kent Walter’s nomination as committee vice chair, replacing co-worker Brian Cole. Trolese remains as MPEC chair. 

The committee endorsed an interim governance task force that will initially have to solicit leadership nominations. It either will report back to MPEC during its August meeting in Colorado or seek approval of its chair with email votes. The task force then will draft language setting requirements on stakeholder group attendance, proxies and absences. 

MPEC also approved Chelan County (Wash.) Public Utility District’s Steven Wickel to a public power seat on the Markets+ Transmission Working Group. Seven other vacancies remain on various stakeholder groups.

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Eversource Announces $500M Cut in Connecticut Investments

Eversource Energy will reduce its investments in Connecticut by about $500 million over the next five years because of the “negative regulatory environment” at the Public Utilities Regulatory Authority (PURA), executives told investors during the company’s first-quarter earnings call May 2. 

“As it stands, regulatory policies in Connecticut discourage investment and utility innovation, as well as our participation in a wide range of clean energy initiatives that rely on our balance sheet,” Eversource CEO Joe Nolan said. 

The PURA has deferred and delayed cost recovery on Eversource’s investments, Nolan continued. The company is also pursuing a legal challenge of a rate cut imposed on its water utility subsidiary. 

“Without recognition that our funding sources rely on a secure and predictable cost-recovery path, we cannot move forward to put additional capital resources on the table,” Nolan said.  

CFO John Moreira added that the company is unwilling “to put capital at risk in relation to advanced metering infrastructure and electric vehicle programs” and is planning to cut spending in the state by nearly $100 million in 2024. But he emphasized that Eversource’s overall forecasted expenditures across its entire system has not changed. 

“Emerging infrastructure needs across our system provide ample opportunity for capital deployment in lieu of using those valuable resources in Connecticut,” Moreira said. 

Following Eversource’s announcement, Connecticut Gov. Ned Lamont (D) bluntly told The Connecticut Mirror he would reappoint PURA Chair Marissa Gillett, whose term ended March 1. 

During Gillett’s time at the PURA, the agency has frequently drawn the ire of Eversource and Avangrid. Lamont has indicated that the companies have pushed for her ouster. 

Gillett has been a proponent of performance-based regulation, and the PURA imposed significant fines on Eversource for poor performance in 2020 during Tropical Storm Isaias and for declining to disclose if it used ratepayer funds to promote new natural gas hookups. 

In an interview with David Roberts on his podcast “Volts” in January, Gillett expressed her intent to make utility profits more dependent on their performance in helping to meet the state’s reliability, affordability and climate priorities. 

“What the fight is in our dockets right now is whether the [performance-based regulation] incentive mechanisms are layered on top of an authorized [return on equity] or whether they’re a component of the ROE,” Gillett said. 

A PURA spokesperson did not respond to RTO Insider’s requests for comment in time for publication, but a spokesperson for Lamont said “Eversource has a legal obligation to maintain grid reliability, and we are confident they will uphold that commitment.” 

Offshore Wind, NH Solar

Eversource also provided an update on its exit from the offshore wind sector, saying it is nearing the completion of the sale of its stake in South Fork Wind and Revolution Wind to Global Infrastructure Partners, and Sunrise Wind to Ørsted. 

“We are on track to close the sale of the three projects over the coming months,” Nolan said. “We are progressing well on the approvals necessary to close these transactions.” 

Eversource anticipates that the cash proceeds from the sale to GIP will total $1.1 billion, Moreira said. 

Nolan noted that onshore and offshore construction has begun on the Revolution Wind project but declined to specify further details on the progress. 

“Now that our offshore wind risk is largely behind us, we are very excited about the future of Eversource, delivering safe and reliable electric, natural gas and water service to our 4.4 million customers,” Nolan said. 

Eversource is also discussing the potential for new investments in solar in New Hampshire, he said. 

“We will likely be proposing an investment opportunity in the months to come,” he added, while highlighting ongoing efforts by the New Hampshire legislature to revamp the state’s Site Evaluation Committee and accelerate permitting and siting processes. 

Nolan said he is encouraged by the state’s interest in utility-owned solar and that the significant amount of land available close to Eversource’s power infrastructure creates a “great opportunity” for investment. 

Eversource reported net income of $521.8 million ($1.49/share) for the first quarter, up 6.2% over the same period last year. 

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NEPOOL Participants Committee Briefs: May 3, 2024

Order 2023-A Compliance Proposal Approved

The NEPOOL Participants Committee approved ISO-NE’s Order 2023-A compliance proposal May 3, making incremental changes to its previous plan approved in March. (See NEPOOL PC Backs ISO-NE Tariff Revisions for Order 2023 Compliance.) 

Order 2023-A “did not necessitate major changes to the Order No. 2023 compliance proposal that the Participants Committee unanimously supported at its March 7 meeting, and most of the proposed incremental changes are in the nature of specific clarifying revisions,” ISO-NE noted. 

The RTO said it is planning to submit two compliance filings for the order by May 14. 

COO Report

ISO-NE COO Vamsi Chadalavada reported that the system peaked in April at 15,657 MW and also reached its lowest load level in recent years, about 6,600 MW. 

The low load levels were caused largely by the continued growth of behind-the-meter solar, which grew in the region by just under 1,100 MW over the past year, Chadalavada said. 

He added that he expects similar rates of growth over the next seven to 10 years, which will likely continue to lower energy prices during peak solar hours and incentivize more battery storage to come online. 

Overall energy market value was about 30% lower than April 2023 as gas prices trended down, Chadalavada said. Imports were significantly reduced because of drought conditions in Québec, he added. 

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Southern Credits Strong Southeast Economy for Earnings Growth

Southern Co.’s financial performance has continued to improve on the back of strong economic growth in Georgia and other Southern states, executives said in an earnings call May 2. 

The company’s businesses “experienced a strong start” in the first quarter of 2024, CFO Dan Tucker said, with Southern reporting an overall net income of $1.13 billion through March 31, up from $862 million for the same period last year. Earnings per share for the quarter stood at $1.03, 13 cents above the company’s estimate and 24 cents higher than the first quarter of 2023. 

The company reported total operating revenue of $6.65 billion, compared to $6.48 billion in the first quarter of 2023, with operating expenses of $4.94 billion, down from $5.26 billion last year.  

Among the factors contributing to income growth, Tucker highlighted stronger-than-expected electricity sales to commercial customers in general and data centers in particular, with revenue from the latter category growing more than 12% in the quarter. Retail electric sales to all classes of customers were up 1.7% from the first quarter of 2023, Tucker said, while industrial sales grew only 0.4% but were “beginning to show signs of recovery following a soft 2023,” with increased revenue from the lumber and paper industries. 

The CFO pointed to the average unemployment rate of 3% across the company’s electric territories and said strong growth is likely to continue, with “a favorable business climate and increased expansion of manufacturing … attracting new households to the Southeast.”  

CEO Chris Womack called the company’s performance “a testament to our team’s collective commitment to serving customers reliably across our business.” He said Southern is “positioned as well or better than any utility company in the country” to continue improving. 

Womack also applauded the end of the “at-times … arduous journey” of constructing units 3 and 4 at the nuclear-powered Plant Vogtle, operated by Southern subsidiary Georgia Power near Waynesboro, Ga. Work on the new reactors wrapped up just days before the call with Unit 4 entering commercial operation on April 29, while Unit 3 did so on July 31, 2023. (See Southern Looks Beyond Vogtle After Challenging 2023.) 

Construction began on units 3 and 4 in 2009, with both originally intended to be operational by 2017. The company has called the reactors the first nuclear generators built in the U.S. in 30 years. However, the project underwent numerous delays and cost overruns, with some observers estimating a final bill of $35 billion, around $21 billion over the initial budget.  

“I cannot be prouder of our team’s perseverance and commitment to getting Vogtle units 3 and 4 completed with the standard of quality fully demonstrated by Unit 3’s performance since it [entered] service last July,” Womack said. “Success on this historic project required the hard work and dedication of tens of thousands of American craft workers and engineers, a committed group of co-owners, and regulators who had the courage to support nuclear when others did not.” 

Womack said completion of the plant was proof “that new nuclear is achievable in the United States [to meet] ever-increasing demands for carbon-free energy … to support our digital economy and society.”  

The CEO expanded on the need for nuclear energy later in the call, saying that “no technology is better suited” for the economy’s needs. At the same time, he admitted that in light of the delays and budget issues at Vogtle, it would likely be “a very long time” before Southern attempts more nuclear construction, and called on the federal government to “provide great leadership” to sway the industry to build more reactors.