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November 16, 2024

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Entergy Touts Louisiana Settlements, Beryl Response in Q2 Earnings

Entergy promoted its response to Hurricane Beryl during its second-quarter earnings call Aug. 1, along with a pair of pending settlements with Louisiana regulators over rates and the Grand Gulf Nuclear Station.

Entergy CEO Drew Marsh told investors to expect settlement filings soon at the Louisiana Public Service Commission to resolve Entergy Louisiana’s disputed rate case and claims of mismanagement at the Grand Gulf Nuclear Station in western Mississippi.

Marsh said the Entergy subsidiary System Energy Resources Inc. (SERI) and the Louisiana PSC have struck a $95 million settlement agreement in principle that will resolve their longstanding clash over Grand Gulf’s poor performance. SERI operates and owns 90% of Grand Gulf and sells the plant’s output to Entergy’s Arkansas, Louisiana, Mississippi and New Orleans affiliates.

Louisiana regulators are the last to accept a settlement agreement related to Grand Gulf; officials in New Orleans, Mississippi and Arkansas already have accepted nearly $500 million in settlements. (See Entergy Earnings Call Focuses on La. Resilience Plan, Nuclear Outage and Settlements and Former Employee Details Failures at Entergy’s Grand Gulf.)

“Pending approval, this settlement substantially resolves the major litigation at SERI and removes an ongoing challenge for many of our stakeholders,” Marsh said. He said Entergy will file a full settlement agreement in the coming days and he expects the Louisiana PSC to address the settlement at its next business and executive meeting Aug. 14.

The PSC maintained for years that ratepayers are owed hundreds of millions of dollars because Entergy mishandled plant operations, undertook an expensive and excessive plant expansion, and engaged in improper accounting and tax violations that shifted costs to ratepayers.

Marsh said a second settlement with the PSC is on the horizon, this one involving Entergy Louisiana’s requested formula rate plan (FRP). He said the settlement involves Entergy dispersing $184 million in customer credits, which includes an increase in income tax benefits for customers, stemming from a 2016-2018 IRS audit of the utility.

The CEO said a successful settlement will mean the utility resolves “all of its outstanding base ratemaking proceedings,” including all issues with FRPs prior to the 2023 case.

Last year, Entergy Louisiana sought an approximately 3% rate increase from customers, or about $173 million (U-36959). The utility argued its recent FRPs have not provided it a “reasonable opportunity to recover the costs of serving its customers.”

Marsh said the two settlements will provide “important clarity” for stakeholders and will allow Entergy and Louisiana regulators to look ahead to focus on “capturing the significant growth opportunities in front of us.” Entergy has identified 5 to 10 GW of new hyperscale data center growth potential across its service territory, he noted.

“We appreciate the hard work of all parties to get to this point,” he said of the negotiations.

Marsh also said Hurricane Beryl in early July affected roughly half of Entergy Texas’ half-million customers. Uprooted trees caused most of the damage and outages, he said. (See MISO: Hurricane Beryl Caused Electrical Island in Texas.)

Entergy estimates it will recover about $75 million to $80 million in total Beryl-related costs.

“We brought a lot of experience and lessons learned from past storms into this effort, which led to timely, safe and cost-effective power restorations,” Marsh said.

He said the storm underscores the need for Entergy Texas’ recently filed Ready Resilience Plan, which calls for spending $335 million over an initial three-year period. However, he said about $200 million is contingent on a grant from the Texas Energy Fund.

Entergy Texas also plans to spend a combined $2.2 billion on new combustion turbine plants in Texas: the 754-MW Legend Power Station in Port Arthur, and the 453-MW Lone Star Power Station in Cleveland, Marsh said. Both plants are expected online in the summer of 2028.

Marsh also said Entergy will accelerate clean energy development, as exemplified by its early June joint development agreement with NextEra Energy Resources for up to 4.5 GW of solar and energy storage.

“Many of our large customers have clean energy goals, and we are expanding our clean energy capacity to support those objectives,” Marsh said.

Entergy reported second-quarter earnings of $49 million ($0.23/share) on an as-reported basis, or $411 million ($1.92/share) on an adjusted basis. This compared to second-quarter 2023 earnings of $391 million ($1.84/share) on an as-reported and an adjusted basis.

The company said the year-over-year decline was attributable mostly to a $317 million settlement charge stemming from a group annuity contract purchased in May to “settle certain pension liabilities.”

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Dominion Highlights Demand Growth, OSW Progress

Dominion Energy earned $572 million in the second quarter of 2024 and logged six peak demand records in July on the back of Virginia’s continued electricity consumption growth, the company said during an earnings call Aug. 1. 

“For full-year 2024, we expect DEV sales growth to be between 4.5% to 5.5%, driven by economic growth, electrification and accelerating data center expansion,” CEO Robert Blue said during the call. 

So far this year, Dominion has connected nine data centers to its system, and it plans to connect an additional six, which will match its recent annual average of 15, Blue said. But the scale of those data centers and their number are growing, while data center developers want them up and running on shorter time frames. 

“We’re taking the steps necessary to ensure our system remains resilient and reliable,” Blue said. “We have accelerated plans for new 500-kV transmission lines and other infrastructure in Northern Virginia, and that remains on track. We were awarded over 150 electric transmission projects totaling $2.5 billion during the PJM open window last December.” 

The current “open window” for PJM’s competitive planning process is expected to be as big, or even larger, due to data center development in Northern Virginia and other parts of the RTO’s footprint, Blue added. 

The growth of data centers has led the Virginia State Corporation Commission to shift around who is paying for wires in the state, Blue said. Since 2020, residential customers’ share of transmission costs has been cut by 10%, while that paid by “GS4” consumers — the largest energy users — has gone up by 9%. 

Dominion also is working to expand generation to meet higher demand, looking into small modular nuclear reactors, natural gas storage, and an additional wind farm off the coast of North Carolina once it finishes with Coastal Virginia Offshore Wind (CVOW). 

The 2.6-GW wind farm is under construction off the coast of Virginia Beach, with 42 monopiles installed so far this season and 30 more having been delivered to the utility on shore, which represents 40% of the project’s total monopiles. 

“After a startup period, during which we successfully calibrated our sound verification process in accordance with our permits, we’ve been able to ramp the installation rate markedly, including achieving two monopile installations in a single day on July 21, and again on July 28,” Blue said. 

Other parts of the massive project continue to be on schedule, with Blue saying Dominion should install the first cable to connect the power plant to the grid during the third quarter. 

“The schedule for the manufacturing of our turbines remains on track,” Blue said. “Fabrication of the towers for our turbines began in June.” 

Dominion will not install its first turbines for the CVOW until 2025, but Blue said that process has begun for the Moray West wind plant off Scotland, which is using the same Siemens Gamesa turbines and already has shipped power to the United Kingdom’s grid. 

“The lessons learned from that project will benefit our project installation in the future,” Blue said. 

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CISA Names 1st Chief AI Officer

Amid growing concerns about the capabilities of artificial intelligence and its cybersecurity threats, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) named its first chief AI officer this week.

In the new role, Lisa Einstein — who has served as CISA’s senior adviser for AI since 2023 and as executive director of the agency’s Cybersecurity Advisory Committee since 2022 — will oversee the agency’s “ongoing efforts to responsibly govern our own uses of AI and to ensure critical infrastructure partners develop and adopt AI in ways that are safe and secure,” CISA said in a statement Aug. 1.

CISA Director Jen Easterly said Einstein has been “central” to CISA’s efforts over the past few years to “come together … to understand and respond to rapid advancements in AI.” She said the new role will help the agency “build AI expertise into [our] fabric … and ensure we are equipped to effectively leverage the power of AI well into the future.”

The agency’s statement called “the responsible use of AI … increasingly relevant for the security of critical infrastructure.” In its webpage on AI, CISA noted its concerns about security challenges associated with the technology, warning that as with previous software advancements, developers must keep a primary focus on security; failure to do so means customers will bear the ultimate burden of security.

Lisa Einstein | CISA

CISA’s previous work on AI includes the “Guidelines for security AI system development” published last November with the U.K.’s National Cyber Security Centre. The document provides a framework for software developers to “build AI systems that function as intended; are available when needed and work without revealing sensitive data to unauthorized parties”; and can be used both by developers creating AI systems from scratch and by those adding AI to existing systems. (See CISA Releases AI Security Guidelines.)

However, CISA sees AI as more than just a threat. Two of the five lines of effort on the agency’s Roadmap for Artificial Intelligence call for it to take advantage of the technology. Line 1 commits CISA to using AI tools “to strengthen cyber defense and support its critical infrastructure mission,” while ensuring “responsible, ethical and safe use.” Line 5 promises CISA will “expand AI expertise in our workforce” by educating current employees on AI software and by recruiting new talent with the required experience.

“I care deeply about CISA’s mission: If we succeed, the critical systems that Americans rely on every day will become safer, more reliable and more capable,” Einstein said. “AI tools could accelerate our progress. But we will only reap their benefits and avoid harms from their misapplication or abuse if we all work together to prioritize safety, security and trustworthiness in the development and deployment of AI tools.”

The ERO Enterprise also has identified AI as a concerning trend, though its focus so far has been the effect of applications requiring large data centers — including AI and cryptocurrency mining — on load growth. In its latest Long-Term Reliability Assessment, released earlier this year, SERC Reliability identified data centers as a key driver for growth in its PJM subregion. (See SERC Highlights DERs, Extreme Weather Challenges in LTRA.)

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WEC Energy Group Concentrates on Natural Gas, Solar to Meet Data Center Growth

WEC Energy Group’s second-quarter earnings call zeroed in on the new natural gas and solar generation the company plans to bolster Wisconsin’s economic resurgence.

WEC Energy Group CEO Scott Lauber said a surge in economic activity in Wisconsin underscores the need for the company’s largest-ever, $24 billion, five-year capital plan.

He said the plan as it stands today focuses on “low-risk and highly executable” projects heavy on natural gas and solar generation.

Lauber said at the end of May, WEC Energy Group closed on its second option at Alliant Energy’s 730-MW West Riverside Energy Center, which has the company trading $100 million for 100 MW of combined cycle natural gas generation.

He also reminded shareholders the company will spend a total of $2.1 billion on 1.2 GW in natural gas generation at its existing Paris and Oak Creek power plant sites. That amount includes a 2-billion-cubic-foot LNG storage facility and a 33-mile gas line to serve the Oak Creek site, which is planned to be converted from coal to gas over multiple years with construction of a combustion turbine plant.

Lauber said the company continues to make meaningful progress on reducing greenhouse gas emissions. He pointed out that in May, the company shuttered coal Units 5 and 6 at the Oak Creek plant, representing more than 500 MW.

“Including these units, since 2018, we have retired nearly 2,500 MW of older, fossil fuel generation,” Lauber said.

Lauber said the company hopes for a decision from the Wisconsin Public Service Commission before the end of the year to spend $580 million to purchase a 90% ownership interest in Invenergy’s 300-MW High Noon Solar Energy Center in southern Wisconsin. High Noon features 300 MW of solar generation and 165 MW of battery storage and is planned to begin operating in 2026.

He said WEC Energy Group’s infrastructure segment expects two more solar farms it will have majority stakes in to come online by the end of the year. Invenergy’s 300-MW Delilah I solar project northeast of Dallas was delayed from its original operational date in June by damage from a hailstorm in northeast Texas. WEC plans to spend about $460 million for a 90% ownership interest in the farm. WEC also will invest $360 million for an 80% ownership interest in Invenergy’s 250-MW Maple Flats solar farm in Illinois.

Meanwhile, Lauber said Microsoft is making “good progress” on its data center campus in southeast Wisconsin.

Microsoft announced in spring that southeast Wisconsin will be the site of a $3.3 billion investment in cloud computing and AI infrastructure through the end of 2026.

Lauber said the company is formulating a refreshed five-year capital plan that he plans to share in the fall that accounts for more data center development.

“We are currently working with Microsoft and developing our plans for our next five-year plan,” Lauber said.

He said WEC Energy Group so far has contemplated only the energy needs of Microsoft’s first 315-acre purchase on the southeast Wisconsin site. Microsoft last fall purchased an additional 1,030 acres, and this week bought a further 173 acres in the area.

“We’ve been working with Microsoft on the needs for the area. Wisconsin’s got a lot of development opportunities, and we want to make sure we hit the capacity requirements we need for the area to support the growth — not just Microsoft, but all the other growth we’re seeing in the region,” Lauber said.

Lauber pledged more filings to add renewable capacity soon. He also said the company is focused on Transmission Co.’s transmission expansion plans in Wisconsin, as well as its own growing distribution needs.

“We’re factoring all that in as we pull together our five-year plan,” he said.

Lauber also said the company hopes for a decision from the Wisconsin PSC by the end of the year on a requested $800 million in electric and gas rate hikes for We Energies and Wisconsin Public Service customers. If approved, a residential customer’s bill would rise by $10 to $11 over 2025 and 2026. Citizens Utility Board has said the proposed increase would drive energy costs too high.

During the quarter, WEC Energy Group reported net income of $211.3 million ($0.67/share), down from $289.7 million ($0.92/share) in the second quarter last year, a 25-cent/share decrease year over year. Revenues were bruised by a warm end of winter, storms and higher operating costs and interest rates.

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Feds Launch Appalachian Hydrogen Hub

The Appalachian Regional Clean Hydrogen Hub is the third of seven regional hydrogen hubs to reach agreement with the U.S. Department of Energy. 

The DOE Office of Clean Energy Demonstrations announced July 31 that the agreement was accompanied by $30 million in funding, the first tranche in what eventually could total as much as $925 million for the Appalachian hub, which is known as ARCH2. 

ARCH2 projects so far are expected to span eastern and central Ohio, southwestern and northern Pennsylvania and almost all of West Virginia, home to Sen. Joe Manchin (I), chair of the Senate Committee on Energy and Natural Resources. 

It is one of the seven regional hydrogen hubs DOE designated in October 2023, with a promise of up to $7 billion in federal funding and an expectation of more than $40 billion in funding from other sources.  

Those designations have begun to be finalized. Earlier in July, DOE announced agreements with the California hub (ARCHES) and Pacific Northwest hub (PNWH2) to begin their Phase 1 work. (See California Reaches Funding Agreement to Launch Hydrogen Hub and Pacific NW Hydrogen Hub Launched with 1st Round of Federal Funds.) 

Phase 1 for ARCH2 will last up to 36 months and entail solidifying planning, development and design activities surrounding site selection, technology deployment, community benefits, labor partnerships and workforce training. 

The hubs are central to the Biden administration’s drive to develop hydrogen as an affordable and effective means of decarbonizing the economy.  

Collectively, the hubs are intended to help form the foundation of a national clean hydrogen network; individually, each will have its own concentration. 

ARCH2, headquartered in Morgantown, W.Va., is intended to develop means of producing, storing, delivering and using clean hydrogen. Many of the projects will involve generating hydrogen from natural gas and developing permanent storage of carbon dioxide, the greenhouse gas that is a by-product of this process. The diversity of projects is one of ARCH2’s differentiating factors. 

The goal is production of more than 1,500 metric tons of hydrogen per day and reduction of 9 million metric tons of carbon dioxide emissions per year. 

This hydrogen is intended to help decarbonize hard-to-abate sectors such as manufacturing and transportation, create thousands of jobs in communities impacted by the clean energy transition and benefit communities overburdened by pollution. 

The net impact of generating hydrogen from natural gas leads some environmental advocates to scoff that it is not “clean hydrogen.” 

In West Virginia, the Charleston Gazette-Mail reported in May on a DOE listening session at which ARCH2 was roundly criticized as a major environmental and economic liability that would risk locking the region into fossil fuel infrastructure while relying on a technology unproven at commercial scale. 

The Ohio River Valley Institute and 54 other organizations petitioned DOE in May to suspend negotiations with ARCH2 until the process became more transparent. 

Spotlight PA reported on fears held by some Pennsylvania residents about the harms ARCH2 might inflict upon public health and the environment. 

But ARCH2 also has many supporters. 

Manchin said in a news release July 31: 

“I was proud to help bring ARCH2 to the Mountain State, which will strengthen America’s energy independence, adding to our all-of-the above approach to energy production through the expansion of hydrogen energy while lowering emissions and bringing good-paying jobs to our state.” 

ARCH2 is led by Batelle and supported by a program management office consisting of Allegheny Science & Technology, GTI Energy and TRC. The National Energy Technology Laboratory also will provide support. 

Development partners include Air Liquids, The Chemours Co., CNX Resources Corp., Enbridge Gas Ohio, Empire Diversified Energy, EQT Corp., Fidelis New Energy, Hog Lick Aggregates, Hope Gas, Independence Hydrogen, KeyState, Plug Power and TC Energy. 

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Environmental Groups Seek Rehearing of MISO Sloped Demand Curve

The Sierra Club, Natural Resources Defense Council and the Sustainable FERC Project are seeking a rehearing of MISO’s sloped demand curve in its capacity auction, arguing that it’s unreasonable for the RTO to require utilities to procure capacity beyond resource adequacy needs.   

FERC last month allowed MISO to replace the vertical demand curve it had been using since 2011 with downward-sloping demand curves. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.) 

The trio claimed in a July 29 filing that FERC’s June acceptance violates the Federal Power Act and Administrative Procedure Act by requiring load-serving entities that opt out of MISO’s voluntary capacity auction to buy more capacity than what MISO deems acceptable (ER23-2977).  

When it installs a sloped demand curve for the 2025/26 Planning Resource Auction, MISO will impose an “x% adder” on load-serving entities that decide not to participate in the capacity auction. The adder will require load-serving entities to secure more capacity than necessary to meet MISO’s planning reserve margins, which are derived from a one-day-in-10-years system reliability standard. The adder will be based on how much excess capacity is procured through the auction in previous years using the sloped demand curves.  

The Sierra Club, NRDC and the Sustainable FERC Project said use of the adder would impose “significant artificial costs” on ratepayers and distort market signals. 

“It is both arbitrary and improper to impose the excess reserve margins created by a market construct whose principal purpose is to vary reserve margins in order to mitigate extreme price fluctuations and better guide resource investment decisions back on entities who are not participating in that market,” the three argued.  

They said forcing load-serving entities to procure extra capacity undermines MISO’s “carefully measured” resource adequacy standard.  

They also said MISO put too much emphasis on using the adder to prevent non-participating load-serving entities from benefiting unfairly from potential excess capacity from other LSEs participating in the auction. Equally as important, the three argued, is the possibility that LSEs using the PRA benefit from opted-out LSEs’ obligation to meet their individual reserve margins in the years when the PRA clears below its reserve margins.  

“The adder is not about ensuring comparability but instead functions as a one-way ratchet to require excess procurement of capacity by utilities that opt out of the PRA,” they told FERC.  

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FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas

SPP’s Markets+ hit a snag July 31 after FERC issued a deficiency letter outlining 16 problems the RTO must address in the tariff it filed for the proposed Western day-ahead market in March (ER24-1658).

How significant a snag remains an open question.

The commission’s letter stipulates that SPP has 60 days to respond. Sources involved in Western market developments, but not authorized to speak for attribution, shared mixed views with RTO Insider about SPP’s ability to adequately resolve the issues on that timeline, particularly if it must consult with stakeholders on any of them.

They also wondered whether the development would shift decision timelines for entities leaning in favor of joining Markets+. They acknowledged uncertainty about the gravity of the deficiencies, but one source pointed to the seeming “structural” nature of some of FERC’s concerns.

For its part, SPP played down the significance in a statement released shortly after FERC released the letter.

“The limited scope of the commission’s requests for additional clarity indicates its broad understanding and acceptance of the Markets+ design as proposed, with a need for more detail on some specific, nuanced market characteristics,” SPP said. “The additional work necessary to respond to the commission’s questions will not negatively impact the Markets+ timeline.”

“The Markets+ development timeline has always had flexibility,” Antoine Lucas, SPP vice president of markets, said in the statement. “We allowed ourselves time expecting an extended review at FERC, and we’re prepared to spend the time necessary to assure the commission we’ve accounted for every possible contingency in the market’s operation.”

The deficiencies outlined in the commission’s letter deal with multiple subjects in the market’s rules, including treatment of transmission, integration with the Western Power Pool’s Western Resource Adequacy Program (WRAP), self-schedules, greenhouse gas pricing provisions and offers from hydroelectric resources.

Under the transmission category, the commission asked SPP to clarify provisions around when capacity is considered unavailable for use in Markets+ and explain the process and timeline for communicating unavailability to market participants.

The commission also sought clarity on how “SPP expects that transmission capacity that is opted out [of the market] but that is not otherwise scheduled will be made available for use” — and on the workings of the opt-out process.

Another deficiency relates to the tariff’s “Markets+ transmission contributors” provision, which allows participants to contribute their transmission rights to a system operated by a transmission service provider not participating in the market, a rule that prompted a protest from PacifiCorp. (See SPP Markets+ Tariff Sparks Concerns for PacifiCorp, NV Energy.)

The commission asked SPP to explain “whether SPP or the Markets+ transmission contributor will be responsible for coordinating transmission schedule changes, curtailments and other operational concerns with the nonparticipating transmission service provider and how this information will be shared, as necessary” and “whether and how ancillary service needs for contributed transmission capacity will be communicated to the Markets+ transmission contributor’s nonparticipating balancing authority.”

It also asked whether Markets+ or the transmission contributor would be responsible “for potential costs associated with usage of the nonparticipating transmission system, including redispatch costs incurred because of schedule changes.”

Regarding the day-ahead market’s integration with WRAP, FERC asked SPP to cite the tariff provisions describing “how Markets+ would ensure that WRAP-related exports, imports or wheel-through transactions’ firm transmission priorities would be treated and/or retained in the Markets+ framework, and how ‘high priority within the market clearing processes’ would ensure preservation of a WRAP-related transaction’s associated transmission priority.”

‘Full Confidence’

The deficiency letter additionally seeks clarity on rules related to the treatment of hydroelectric resources, provisions important to Canada-based Powerex and federal power agency Bonneville Power Administration — whose staff in March recommended the agency choose Markets+ over CAISO’s Extended Day-Ahead Market. (See BPA Staff Recommends Markets+ over EDAM.)

FERC’s concerns centered around the calculation of the seasonal hydroelectric offer curve (SHOC), which is designed to estimate the opportunity costs for hydroelectric resources so those costs can be factored into their market offers.

FERC’s deficiency letter comes a week after all four U.S. senators from Oregon and Washington sent a letter to BPA Administrator John Hairston urging the agency to delay its decision on joining a day-ahead market until more developments play out around Markets+ and EDAM. (See NW Senators Urge BPA to Delay Day-ahead Market Decision.)

“The SPP Markets+ tariff was filed at FERC in April and is still under review,” the senators wrote. “FERC has a new slate of commissioners, and it remains unclear whether the tariff, as submitted, will be approved or found deficient. Indeed, deficiency letters for novel filings are common and require additional time and effort to resolve.”

“The innovative and complex market structure of Markets+ is proposed under a standalone tariff,” SPP’s Lucas said in the RTO’s statement. “We’ve always anticipated that a deficiency letter from FERC was a possibility given the intricacies of the market structure. We have full confidence we can quickly and effectively address FERC’s request.”

CAISO’s EDAM tariff won relatively clean approval from FERC last December, with the commission only rejecting a “separable” and temporary measure designed to ensure interim compensation for transmission providers that suffer financial losses during their transition into the new market. The commission approved the ISO’s revised version of that measure in June. (See FERC Approves EDAM Tx Revenue Recovery Plan.)

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NERC Planning Task Force on EV Grid Impacts

NERC’s Reliability and Security Technical Committee (RSTC) hopes to approve the formation of a task force examining the impact of electric vehicles on grid reliability by the end of this week, ERO staff said. 

Speaking to the System Planning Impacts of Distributed Energy Resources (SPIDER) Working Group on July 31, JP Skeath, NERC senior engineer for bulk power system security and grid transformation, said the RSTC is holding an electronic vote to allow the task force to begin work before the committee’s next formal meeting, which is not scheduled until September. 

Skeath said RSTC Secretary Stephen Crutchfield told him that day the online vote, which ends on Aug. 2, had yet to reach a quorum. However, he said the 17 votes in favor received so far made staff “assume the vote is going to be” successful. If so, Skeath continued, the committee will start forming the task force right away, with recruitment targeting EV manufacturers among other stakeholders. 

The EV task force would report directly to the RSTC rather than to any of its subcommittees or working groups, Skeath said. However, he added that “part of the expected scope is to be able to characterize specific types of risks and potentially reassign future work … a year or so” after work begins. The task force may tap specific groups to study further mitigation of the risks identified. 

ERO stakeholders have become increasingly concerned about the impact of EVs on the grid, with their rate of adoption in North America rising significantly over the past several years. According to data collected by the California Energy Commission last year — which Skeath shared in his presentation — cumulative national EV sales since 2010 reached more than 3.25 million in the last quarter of 2022, with nearly 250,000 of those sales occurring in just that quarter. 

“We’re starting to see the exponential [growth] part … of that type of adoption curve,” Skeath said. “The cumulative and instant sales are just growing in the last few years, where EVs are starting to become a … larger market share in … light-duty vehicles.” 

The growing EV deployment also has led to expanding loads for grid planners to deal with, he continued. In a 2022 analysis, National Grid examined current EV charging sites, including locations like parking garages with one or two chargers, mixed-use retail sites and large locations like truck stops.  

While most of the sites analyzed accounted for less than 5 MW of load in 2022, National Grid projected that by 2045, a smaller site could require 10 MW to 20 MW — between an outdoor stadium and a small town — while the largest locations could exceed 40 MW, the same as a large industrial plant. 

“That started the idea of [asking] what type of load will be friendly to the rest of the grid, and what type of load will be unfriendly to the rest of the grid?” Skeath said. 

The ERO has contributed to several previous studies on EVs’ grid reliability impacts. In April 2023, NERC, WECC and the California Mobility Center released a report identifying “grid-friendly” and “grid-unfriendly” behavior — meaning, respectively, electric applications that support stable operation of the grid, and those that aim to maintain a constant current or power level despite the effect it might have on a weakened system. (See NERC, WECC Outline EV Charging Reliability Impacts.) 

NERC built on 2023’s study with a 2024 white paper recommending EV and charger manufacturers improve their collaboration with electric utilities and that transmission planners incorporate charger performance into their planning criteria. (See NERC Addresses Growing EV Risks in White Paper.) 

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FERC Approves CAISO Request to Lift Soft Offer Cap for Hydro, Storage

FERC on July 31 accepted CAISO’s proposal to allow for storage resources to bid above the ISO’s $1,000/MWh soft offer cap in the real-time market to account for their intraday opportunity costs (ER24-2168).

The approved tariff revisions also remove the requirement that scheduling coordinators submit reference level adjustment requests (RLCR) to raise their default energy bids (DEBs) above $1,000/MWh when their DEBs would, by their own calculations, rise above $1,000/MWh.

The proposal is the result of work by CAISO’s Price Formation Enhancements Working Group and the Storage Bid Cost Recovery and Default Energy Bids initiative. It revises the process under FERC Order 831 by which the ISO verifies a unit’s cost-based offers in the energy market. (See CAISO Moves for Expedited Change to Soft Offer Cap.)

Issued in 2016, Order 831 set a “soft” cap on energy bids of $1,000 that could be exceeded, up to a “hard” cap of $2,000, to reflect a resource’s verifiable costs. Each grid operator was required to propose a process for verifying offers over the soft cap.

CAISO, however, found that the new paradigm, approved in 2020, inhibited storage and hydroelectric resources, two types vital to maintaining adequate supply during the summer.

“For resources that operate based on finite resources like reservoir levels or state-of-charge, supplying energy earlier in the day often means that they cannot supply energy later at the time of higher demand,” FERC said in its order. “CAISO states that this is a significant concern because if these resources are depleted earlier in the day, CAISO must depend on a more limited pool of resources to meet its later net peak demand.”

Removing the RLCR restriction will enable cost-justified bidding, promoting more efficient dispatch on constrained days, FERC said. “The artificial restriction to cap DEBs at $1,000/MWh is unnecessary and counterproductive to using DEBs for cost-verification.”

CAISO’s Department of Market Monitoring agreed, having argued that requiring scheduling coordinators to submit RLCRs is unnecessary because the formulas used to calculate DEBs are well established and reflect the marginal cost of a resource. The department also agreed the cap should be removed for energy-limited resources because of the technical limitations they face. Portland General Electric and the California Energy Storage Alliance also supported the proposal.

While the DMM generally supported the tariff revisions, it also said the proposed changes should not apply to the entire day because a static bid cap cannot target specific hours when intraday opportunity costs are most likely to exceed $1,000/MWh.

The California Public Utilities Commission also argued that the proposed changes are not targeted enough to address the intraday opportunity costs of hydro resources. Lifting the cap in the day-ahead market is not necessary because the market is already able to optimize resource schedules, it said.

“DMM and CPUC assert that the bid cap proposed by CAISO would allow energy storage resources to bid substantially in excess of their intraday opportunity costs during high priced hours when the system is tight and the opportunity cost is known to approach zero,” FERC summarized.

The department also raised concerns about the tariff revisions’ potential to exacerbate existing flaws in bid cost recovery, an issue being addressed in the ISO’s bid cost recovery initiative. (See CAISO Kicks Off Storage Bid Cost Recovery Stakeholder Initiative.)

The CPUC also argued that the hydro DEB formula was not designed for above-cap bidding and therefore does not result in values that satisfy Order 831 cost justification requirements.

CAISO responded by reiterating its belief that artificially capping any resource’s DEB at $1,000/MWh in the day-ahead market could lead to inefficient scheduling. CPUC’s arguments regarding the hydro DEB formula were outside the scope of the proceeding, the ISO argued, and neither it nor the DMM provided evidence that proposing a static bid cap throughout the day rather than targeting specific hours was unreasonable.

FERC disagreed with the DMM’s and CPUC’s arguments.

“We find that CAISO’s proposal will help to ensure that energy-limited resources are able to reflect their opportunity costs in their cost verified bids, similar to other resources,” FERC stated. “We find that accounting for these opportunity costs will enable CAISO to more optimally manage these resources’ energy limitations over the day, and thereby improve CAISO’s ability to reliably and economically meet its net peak demand.”

The tariff revisions become effective Aug. 1. Commissioners Lindsay See and Judy Chang did not participate in the order.

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Maryland PSC Approves Grid Upgrades for New Data Center

Maryland is setting itself up to compete with Northern Virginia’s Data Center Alley with a 2,100-acre data center campus in Frederick County, and on July 31, the Maryland Public Service Commission granted a waiver for Potomac Edison Co. to install two 230-kV lines to help connect four data centers from the campus to a new substation. 

The 3-1 vote on the waiver allows Potomac Edison to begin construction on the lines in September without first requesting a certificate of public convenience and necessity (CPCN), a much longer and more expensive process.  

Commissioner Bonnie Suchman cast the single no vote, arguing the waiver could open the door for more waiver requests for similar line additions for more data centers, with other customers picking up the bill. 

Potomac Edison’s customers in Frederick County don’t need the upgrades at present, Suchman said. “Upgrades are only coming because of this new data center. … You’re going to get more data centers coming in, and more data centers are going to put more burdens on the system, and then you’re going to come to us for a waiver, and we’re going to sort of rush all this stuff through. 

“The data center may come or not, but the one thing I am seeing is an increase in the cost for the network that’s going to be borne by the ratepayer,” she said. 

According to commission staff, however, the project meets specific legal standards in the state’s public utilities code that require the PSC to grant the waiver: The new lines won’t require the utility to secure new property or rights-of-ways or to install bigger or taller structures for increased voltage or larger conductors. 

The Potomac Edison lines will be “loop lines” that run from an existing 230-kV line to a new substation to be built for the data center and then back to the main line. Each line will be 1,100 feet long and use the same type of wires as the existing line, and will include eight new poles, none of which will be taller than existing poles.  

The staff report also said the new lines and other system upgrades, including a switching station expansion, will mitigate potential thermal overloads and voltage violations the new data centers could cause on the main line, as identified by PJM. 

“PJM did that specifically for reliability reasons … not only to take into consideration [the data center’s] anticipated load, but the other load currently being served and to be served in that area, altogether about 1,350 MW,” said Joey Tsu-Yi Chen, corporate counsel for Potomac Edison. “We do not want to see a situation, in fact, cannot, where we have no more than 300 MW of load that would be interrupted by any particular criteria.” 

However, PJM spokesperson Jeff Shields said the RTO neither planned nor approved the two lines. Rather, FirstEnergy, which owns Potomac Edison, included the project in a supplemental filing to the RTO’s Transmission Expansion Advisory Committee in October 2023. 

Data Center Alley North?

Reliability aside, Chen told the commission the waiver was needed so the new lines could be built to meet the data center’s timeline. A full CPCN review would not meet “their timing needs for their project,” he said ― underlining the disconnect between digital and regulatory time frames, and Suchman’s concern Potomac Edison’s waiver request could be the first of many. 

Maryland has been promoting itself as a nearby, attractive alternative to Northern Virginia, home to hundreds of data centers and skyrocketing power demand. Gov. Wes Moore (D) rolled out the welcome mat in May when he signed the Critical Infrastructure Streamlining Act of 2024 (S.B. 474), waiving the need for data centers to get CPCNs for their fossil fuel-powered backup generators.  

The Frederick County data centers could provide a glimpse of what’s to come. The developer for the project is Rowan Digital Infrastructure, which provides “turnkey data center campus solutions” with “de-risked development timelines,” according to the company website. 

The data centers will cover about 145 acres in the larger, 2,100-acre Quantum Frederick data center campus being planned by developer Quantum Loophole. Rowan’s website describes its project as a multi-building facility with 300 MW of power to start and the potential to expand to 450 MW. 

The Frederick County site offers “near-term power interconnection dates [and] competitive power pricing … [and can] deliver the initial 300 MW by late 2025, providing a high-value alternative to the congested Ashburn corridor” in Northern Virginia. 

Quantum also has big plans for the site, which it intends to connect to its data center hub in Northern Virginia with a 40-mile fiber optic network ring. 

“At full capacity, the 34 conduits will hold more than 235,000 strands of fiber to transmit data between the two hubs in under one millisecond Round Trip Time (RTT),” a company press release said.