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November 9, 2024

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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. 

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Exelon Focuses on ComEd, Other Rate Cases in Q1 Earnings Call

Exelon CEO Calvin Butler opened the company’s first-quarter earnings call May 2 with a tribute to his predecessor, Chris Crane, who died April 13, then quickly turned to the business at hand: the rate cases, from Illinois to D.C., that could have major impacts on the utility’s bottom line and profitability. 

“A key goal this year is to improve our regulatory outlook in Illinois,” Butler said, referring to the Illinois Commerce Commission’s rejection of Commonwealth Edison’s integrated grid plan Dec. 14 for failing to meet core provisions of the state’s Climate and Equitable Jobs Act.  

The ICC sent both ComEd and Ameren Illinois back to the drawing board after finding the utilities had not sufficiently incorporated customer affordability into their plans or outlined how 40% of plan benefits would go to low-income and environmental justice communities, “among other shortcomings,” according to the commission’s announcement. 

With a 90-day deadline for submitting a revised plan, “the ComEd team got to work the day after the order and worked tirelessly with key stakeholders … to create an updated plan that … is thoroughly responsive to the ICC’s direction,” Butler said. 

“We outlined in detail, for every customer and community, [the] benefits from the clean energy transition,” as well as providing an affordability analysis, CFO Jeanne Jones said. “Specifically, through focused grid investments in disadvantaged communities, more than 40% of the benefits of grid modernization and clean energy have been demonstrated to support equity-investment-eligible communities’ customers.” 

The revised plan was submitted March 13, Butler reported. The ICC has scheduled intervenor testimony, rebuttal and an evidentiary hearing in May, June and August, respectively, with a final decision expected in December. 

Jones also provided a rundown of recently approved and pending rate cases across Exelon’s utilities, beginning with the Delaware Public Service Commission’s approval April 18 of a settlement in Delmarva Power’s rate case, allowing a $27.8 million increase in the utility’s revenue request. 

Pending regulatory approvals include multiyear rate cases for Pepco in both D.C. and Maryland, with decisions expected this summer or early fall, and PECO Energy oil and gas rate cases in Pennsylvania, expected in either November or December. 

Data Centers in Pa.?

Exelon’s earnings edged down in the first quarter of 2024 compared to the year before, Jones said. The company’s non-GAAP net income was $685 million ($0.68/share), versus $696 million ($0.70/share) for the same period in 2023. Corresponding GAAP figures were $658 million net income ($0.66/share) for Q1 2024 and $669 million net income ($0.67/share) in 2023. 

Butler pointed to the combination of a warmer-than-normal winter and severe storms as factors in the decrease. Jones also cited higher costs from storm damage, as well as high interest rates and higher levels of debt at both the company and its utilities. 

With data centers and the resulting demand growth exploding across the country, Aidan Kelly, an analyst with J.P. Morgan Securities, asked if Pennsylvania might be a prime candidate for data center development, with its large natural gas reserves at the Marcellus and Utica shales. 

“The short answer is ‘yes,’” Butler said. “And I would tell you that we continue to see significant activity around high-density load growth in general,” with both Illinois and Pennsylvania in the mix. 

“We have continued to see different businesses, including some interest from data centers in the PECO territory,” said utility CEO David Velazquez. “We have the infrastructure to support that … on the generation side and also have the transmission infrastructure.” 

“In addition to data centers, we’re seeing electrification; we’re seeing development around the South Philadelphia area,” Exelon COO Michael Innocenzo added. “So, lots of opportunities for growth in all sorts of electrification.”

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OSW, Data Centers Loom Large in Dominion’s Outlook

Dominion Energy expects to start installing monopiles for the Coastal Virginia Offshore Wind (CVOW) project between May 6 and 8, CEO Robert Blue told analysts May 2 on the company’s first-quarter earnings call. 

Construction is moving forward despite a lawsuit seeking to stop the project, alleging its federal approvals violate the Administrative Procedures Act and the Endangered Species Act, Blue said. (See Opponents Sue to Halt Coastal Virginia Offshore Wind.) 

Proponents of the project have asked the U.S. District Court for D.C. to stop the project, but the suit is still pending, with Dominion set to file a response May 6 and its opponents their answer to that May 9.  

Blue said the complaint was without merit and that he expects the court to deny the plaintiffs’ request for a preliminary injunction. He said similar litigation against offshore wind has been rejected by an appeals court. 

“Let me just reiterate, the project is proceeding on time and on budget consistent with the timelines and estimates previously provided,” Blue said. 

CVOW got its eleventh and final required permit and Dominion has received 36 monopiles from its supplier, a fifth of the total. It expects more monopile deliveries in the coming weeks and will be installing them over two seasons — this year and next, Blue said. 

Offshore construction contractor Deme recently completed a project off Scotland that uses the same Siemens Gamesa wind turbine that CVOW will use, and the lessons learned there will benefit Dominion’s wind farm, Blue said. 

Dominion expects the levelized cost of energy (LCOE) for CVOW to be $73/MWh, which is down modestly from its last forecast due to higher renewable energy credit (REC) prices. That means the CVOW is expected to produce more benefits for customers, Blue said. 

“We remain well below the legislative prudency cap on this metric, and I would point out well below the PPA prices being considered in other parts of the country,” he added. 

Return to Capacity Auctions

Dominion has so far invested $3.5 billion in CVOW and remains on track to bring that up to $6 billion by the end of the year, with 93% of project costs fixed, Blue said. 

The other big issue in Dominion’s territory is data center growth in Loudoun County, Va., outside of D.C., and home to Data Center Alley, the largest group of data centers in the world. 

“In aggregate, we’ve connected 94 data centers with over 4 GW of capacity over the last approximately five years,” Blue said. “We expect to connect an additional 15 data centers in 2024. Northern Virginia leads the world in data center markets.” 

Both the number and the size of data centers seeking service in the area has grown in recent years. Dominion used to get requests to serve data centers requiring about 30 MW, but now individual buildings can use 60 to 90 MW, while the utility has gotten some requests for big campuses with multiple buildings drawing 300 MW to several gigawatts, Blue said. That growth in data center demand is reflected in PJM’s capacity market. 

“Last month, PJM released its capacity auction planning parameters,” Blue said. “The results aligned with our analysis of low growth and the need for requisite dispatchable supply resources included in our 2023 IRP. This independent modeling also validates the need to expediently progress the recurring local and PJM regional transmission planning and expansion process, and our decision to expedite numerous projects over the last two years.” 

Dominion has accelerated plans for new 500-kV transmission lines and other infrastructure in Northern Virginia and was awarded over 150 projects totaling $2.5 billion from PJM’s regional plan released in December, he added. (See PJM Board Approves $5 Billion Transmission Expansion.) 

The recent capacity market reforms and those latest assumptions mean Dominion will be participating in the main PJM Reliability Pricing Model auction once again, instead of using the Fixed Resource Requirement alternative as it had in recent years. It must decide which to pick later in May, with the auction set for July 17. 

“It makes sense for us to return to the capacity auction starting with the 2025/26 auction — [it] returns us [to] the way we did business for many years,” Blue said. “It doesn’t change guidance, doesn’t change the way we operate our system, or the way we think about the world.” 

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Ørsted Reports Steadier Course as US Market Stabilizes

The world’s leading offshore wind developer charted a path forward from the industry’s recent turmoil as it released its first-quarter financial results May 2. 

In a conference call with financial analysts, Ørsted CEO Mads Nipper said the company is confident the plan is coming together for the successful construction of Revolution Wind and Sunrise Wind off the Northeast U.S. coast. 

He outlined steps taken to prevent a repeat of the series of setbacks that cost Ørsted billions of Danish kroner in 2023 as it tried to navigate the U.S. offshore wind market’s growing pains. 

The company said its financials for the first three months of 2024 were in line with expectations, with offshore earnings 18% higher than in the same quarter in 2023. The company’s stock closed 2.7% higher May 2, a marked contrast to the plunges that followed some of the company’s 2023 announcements. 

Nipper and CFO Trond Westlie laid out some first-quarter highlights for Ørsted: 

    • The company secured a provisional contract with New York for Sunrise Wind to replace a previous deal that did not cover rising construction costs; this allowed the company to reverse some of the impairments it previously assigned to that project. 
    • Federal regulators green-lighted construction of the 924-MW Sunrise. (See BOEM Approves NY’s Sunrise Wind OSW Project.) 
    • The company is moving to take full ownership of Sunrise as 50-50 partner Eversource completes its exit from offshore development. (See Eversource Finds OSW Buyer, Takes $1.95B Hit for 2023.) 
    • Ørsted submitted a proposal for a 1.2-GW project it calls Starboard Wind to Connecticut and Rhode Island. 
    • It is moving to secure heavy structural steel for monopile foundations and additional installation vessel capacity — two critical potential roadblocks to project construction. 
    • Ørsted and Eversource completed construction of South Fork, the first utility-scale offshore wind farm in U.S. waters; final commissioning is expected in the second quarter. (See First Large US Offshore Wind Farm Complete.) 
    • Ørsted paid out 700 million kroner — about $100 million U.S. — for wind wake losses at Hornsea 1 attributed to Hornsea 2. Wind wake loss, which is output reduction in downwind turbines because of turbulence from upwind turbines, is expected to be an issue as more and larger turbines are installed. (See Researchers Modeling Jet Stream Interference with OSW.) 
    • March was the first month ever that the company burned no coal at its seven combined heat and power plants. 
    • Ørsted agreed to sell four U.S. onshore wind farms rated at 957 MW as part of its farm-down program, in which it sells operating assets to raise money for future projects. 

When Nipper and Westlie concluded their presentations, the Q&A portion conference call became a wide-ranging forum on prospects for Ørsted amid an industry reset. 

Some of the talking points: 

What happens if Ørsted needs more monopile capacity? 

“What we are very happy to see is that the actual production of the monopiles from our key supplier for three of our projects has stabilized so now the planning becomes safer,” Nipper said. 

If Ørsted won a contract for Starboard, would that not push the company above its targets for development in the United States? 

“No, this would be with all possible likelihood for a post-2030 [commercial operation date] and COD flexibility was one of the key criteria we assessed when deciding where and with what to bid,” Nipper said. 

Regarding Ørsted’s announcement May 1 that it had secured licenses to develop up to 4.8 GW of offshore wind in Australia: Isn’t Australia a rather immature market with no offshore wind supply chain? Didn’t Ørsted just go through this scenario in the United States? 

“So, this is not a market where you should be concerned that we will end up in the U.S. situation. Because we have learned — the entire industry have learned — that it is certainly a challenge to build a new industry entirely from scratch and I think both we and the entire industry are taking those learnings,” Nipper said. He added, however, that it is important to build longer-term opportunity, and Ørsted can do it at very limited cost with this move in Australia. “We will go there with very open eyes as to what are the risks that would come with an entirely new market.” 

New York just saw an entire wind solicitation collapse because the three contracts were relying on an 18-MW GE Vernova turbine design whose development was canceled. (See NY Offshore Wind Plans Implode Again.) What turbine are you planning for Sunrise, and is it on the market yet? 

“We can confirm that this is not on a future model that we are hoping will be there,” Nipper said, without providing details. (He had disclosed earlier in the call that 11-GW Siemens Gamesa turbines would be installed at Sunrise.) 

Ørsted’s problems in the United States probably can be traced to the defunding of the Bureau of Ocean Energy Management five years ago. What risk do you face if a future president attempts to intervene in the market again? 

“Yes, you’re right, that there are certainly risks that we are very explicitly handling. Most importantly [will be] to ensure that we have all permits in place [before the 2025 inauguration], which we feel comfortable we will,” Nipper said, adding that Ørsted put so much timeline flexibility in the Starboard bid for exactly that reason. He said, however, that bipartisan support for offshore wind has evolved over those five years. “Despite some of the rhetoric, this is being recognized that a very high joint priority in both blue and red states is job creation and we do see being recognized that offshore is creating jobs.” 

Do you think offshore wind development costs have peaked, or even reached a deflationary environment? 

“I don’t think it’s possible to say whether there’s a peak in pricing. But it is a fact that the supply chain inflation is a lot less steep than where we came from. But it is still too early to say whether that is flattening or even deflationary,” Nipper said. 

How is the farm-down program going? 

“We are continuing as we have planned, and what we actually see in the market is that even though the pricing of the assets has been higher or lower due to the fact of the interest rate … we see a slightly better sort of market and also interest in that regard,” Westlie said.  

Do you plan to keep a strong presence in the U.S. onshore wind market or rebalance to Europe? 

“Clearly the U.S. will remain our biggest onshore market. We do have a pipeline, and one where we also see several attractive opportunities and also are quite excited about some of the opportunities that are in combined generation and storage,” Nipper said. 

Any update on Ørsted’s plans to reuse equipment from the canceled Ocean Wind projects in New Jersey or the Skipjack project, which is in limbo in Maryland? (See Ørsted Cancels Ocean Wind, Suspends Skipjack and Ørsted Cancels Skipjack Wind Agreement with Maryland.) 

“Not a lot of update. We do continue to mature those opportunities,” Nipper said.