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November 5, 2024

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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. 

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Senators Call for ‘Increased Accountability and Transparency’ at ISO-NE

In a wide-ranging letter dated April 30, four U.S. senators called for improved transparency and accountability from ISO-NE and asked the RTO to increase its facilitation of the clean energy transition.   

Sens. Ed Markey (D-Mass.), Sheldon Whitehouse (D-R.I.), Elizabeth Warren (D-Mass.) and Bernie Sanders (I-Vt.) applauded ISO-NE’s “ongoing progress on transparency, longer-term transmission planning and resource accreditation,” but said more changes are needed. 

“ISO-NE must address issues of governance with increased accountability and transparency, strategically build out transmission capacity and reshape the ISO-NE market structures that have a history of unfairly subsidizing existing fossil fuel generation,” the senators wrote, requesting a written response by May 10. 

The letter was led by Markey, a frequent critic of ISO-NE. In 2023, Markey introduced a bill to increase the transmission planning and transparency requirements for RTOs, which was endorsed by several environmental organizations. (See Dems Introduce Bill on Transmission Planning, RTO Transparency.) 

ISO-NE spokesperson Mary Cate Colapietro said the RTO is preparing a response to the letter and added that it remains focused on reliability and “managing wholesale electricity markets that will support the new technologies and industry innovations necessary to serve all New Englanders now and in the future.”  

Governance Recommendations

The senators urged ISO-NE to diversify its board of directors to better represent consumer, climate and environmental justice perspectives. They also called on ISO-NE to allow stakeholders to vote on individual candidates for the board, instead of just a single proposed slate of candidates.  

The board also should open its meetings to the public and make efforts to incorporate community feedback and questions into their proceedings, the senators added.  

The senators also criticized the voting structure within NEPOOL, noting that state consumer advocates “hold less than 2% of the voting power in NEPOOL.” 

While commending ISO-NE’s agreement to hire a policy adviser focused on community engagement and environmental justice, the senators asked ISO-NE to develop a larger environmental justice team “to uplift lived experiences, account for social costs and benefits, and align with larger environmental justice priorities.”  

The senators also asked ISO-NE to “engage more deeply with the ISO-NE Consumer Liaison Group (CLG) to ensure that public interest is a core tenet of all future decisions and policies.”  

Following the election of a group of climate activists to the CLG’s coordinating committee in December 2022, ISO-NE has seen strong participation — and faced increased criticism — at CLG meetings. (See Climate Activists Take Over Small Piece of ISO-NE.)

Interactions between ISO and NEPOOL officials and climate activists at the CLG at times have been testy. Activists have argued ISO-NE and NEPOOL are biased toward fossil fuel interests and aren’t doing enough to facilitate decarbonization, while ISO-NE has stressed that it must remain fuel-neutral and is constrained by federal and state policy.  

An April 1 letter to ISO-NE by two NEPOOL members criticized members of the CLG coordinating committee for advocating for climate action and urged ISO-NE to prohibit the committee from “lobbying from within.” 

The letter was written by Lisa Linowes, executive director of the Industrial Wind Action Group, an antirenewables advocacy organization, and William Short, a consultant representing multiple companies at NEPOOL.  

“If this level of advocacy persists, we would argue that the CLG be abolished,” Linowes and Short argued. 

The senators urged board members and ISO-NE officials to “continue to participate in CLG meetings in order to fully assess and understand the impacts of its decisions on the communities it serves and who pay for its operation.” 

Market and Planning Recommendations

The senators called on ISO-NE to redouble its intra- and interregional transmission planning efforts, while praising the proposed cost-allocation framework for long-term transmission projects approved by the NEPOOL Participants Committee in early April. (See NEPOOL PC Supports Additional Delay of FCA 19.) 

“In partnership with state governments, ISO-NE should embrace a much more ambitious paradigm for interregional grid coordination and planning with neighboring balancing authorities on both sides of the border,” the senators wrote. 

Regarding ISO-NE’s in-development resource capacity accreditation (RCA) updates, the senators wrote that ISO-NE should “expand the scope of RCA to better reflect gas plant performance, and ensure accreditation values adequately incentivize the resources states’ policies demand to participate in the capacity markets.”  

The RCA updates likely will significantly change the revenue resources can earn in the capacity market. ISO-NE’s initial analysis indicated the updates would hurt the value of gas, oil and battery resources, and benefit wind, energy efficiency and hydro resources. (See NEPOOL Markets Committee Briefs: Feb. 6, 2024.) 

Despite recent efforts to enable smaller resources to participate in ISO-NE’s wholesale markets, stakeholders have argued the markets remain prohibitive to aggregations of distributed resources. (See ISO-NE CLG Highlights Importance of Demand Response.) 

The senators expressed their hope the capacity market changes will prevent expensive out-of-market agreements to preserve grid reliability and stressed that any future out-of-market arrangements must be based on “clear, cohesive and transparent evidence.” 

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NC Residents Criticize Duke’s Pace of Coal Retirements, Reliance on Gas in Carbon Plan

North Carolina residents in an online hearing April 23 called upon the Utilities Commission to address Duke Energy’s preferred carbon plan, criticizing its slow pace of coal plant retirements and increase in gas plants compared to other options. 

The plan projects three “pathways” the utility could take to reduce its carbon emissions by 70% from 2005 levels by 2030, 2033 and 2038. All three pathways would eliminate Duke’s carbon emissions by 2050, according to the plan, but details concerning the utility’s resource mix beyond 2038 are not mentioned. The commission must approve any plan Duke puts forward before it is enacted. 

Pathway 3, with the most gradual pace of retirements and several large coal plant retirements delayed until 2036, is Duke’s preferred, least-risk option. The company would add 5,625 MW of solar by 2031, 2,700 MW of battery energy storage by 2031, 1,200 MW of onshore wind by 2033 and approximately 4,400 MW of new gas-fired generation by 2032. 

The speakers, all residents within Duke’s North Carolina footprint, took issue with the company “kicking the can,” as resident Allison Kubisko said, on the state’s 2030 goal of reducing emissions by 70% by delaying coal plant retirements. 

“I want to stress my concern about climate change and the need to reduce carbon emissions now. … Later is too late to reduce our emissions and to reduce our fossil fuel use,” Kubisko said. 

The law enacting the 2030 deadline, HB951, does include stipulations for when the commission can issue a delay, including to maintain existing grid reliability or to enable the construction of specific nuclear or wind generation. However, such delays cannot exceed two years, raising concerns about “pushback from the [North Carolina] legislature or even possible legal challenges” should the commission accept Duke’s plan unaltered, resident Matthew Mayers said.  

Putting off the state’s emissions goals could also exacerbate environmental and health issues, Durham resident Betty Matteson said. 

“Our children and grandchildren love to spend time” at Wrightsville Beach, she said. “Scientists tell us that the warming climate will cause rising sea levels and increasingly frequent and intense hurricanes … and I wonder when sea-level rise or a destructive hurricane will threaten our beloved Wrightsville.” 

Residents were also concerned about the buildout of gas-fired generation, particularly in neighboring South Carolina. Generation constructed there would not contribute to emissions reported in North Carolina, they said, even if the state’s residents used its power. Pathway 3 has over 7 GW of gas-fired power in place in 2038, compared to over 6 GW in Pathway 2 and just over 5.3 GW in Pathway 1. 

Matteson expressed specific concerns about residents’ cardiovascular health, which she said is known to be affected by air pollution from burning fossil fuels. She cited North Carolina State University research linking gas pipeline prevalence to nearby residents’ health and economic status as a reason to halt gas infrastructure buildout.  

“By reducing our dependence on fossil fuels, our children could enjoy a healthier future,” she said. “Why is this not the No. 1 priority of the 2024 carbon plan?” 

Cost Analysis

In addition to concerns surrounding emissions, residents opposed the carbon plan’s potential costs to Duke customers. 

Resident Judith Maddox and others said Duke prioritized its bottom line over actual costs in its favored plan. North Carolina regulations allow utilities to recoup gas infrastructure costs, “which makes it profitable for them to request such buildings,” she said. “Then they can turn around and charge customers for the gas costs that are required, whereas wind and solar do not have fuel costs.” 

In the plan Duke labeled as riskiest, Pathway 1, the company tacked on a 20% adder, or “cost risk premium,” to capital costs to account for the “extraordinarily aggressive” energy transition. This pathway would see 2.4 GW of offshore wind installed in the state by 2035, for example. 

This cost is “arbitrary,” resident Lisa Dietz said, given that Duke’s plan for gas and nuclear in the other two pathways is “overly optimistic … in terms of cost, timeline and future fuel availability.” 

In-person public hearings on Duke’s carbon plan also took place in Wilmington and Durham on April 29 and 30, respectively. 

Company spokesperson Bill Norton said the hearings were “about how [Duke] is going to supply the reliable, clean energy need to support North Carolina’s growing economy — while also getting out of coal and reinvesting in power plant communities to lower the cost of the energy transition for all customers.” 

Following testimony from public staff May 28 and the commission’s technical conference June 17, Duke will have the opportunity to file rebuttal testimony by July 1. The commission’s final evidentiary hearing on the carbon plan will occur July 22. 

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Stakeholders Deliver Negative Reactions to Proposed MISO Capacity Accreditation at FERC

Stakeholder voices criticizing the design of MISO’s proposed, probabilistic capacity accreditation outnumbered those expressing support before FERC.  

MISO filed with FERC for a new, direct loss-of-load accreditation style in late March. The RTO wants to move to a capacity accreditation for all resources that blends resources’ historical availability with projected performance during simulated loss-of-load events (ER24-1638). (See MISO: New Capacity Accreditation Filing Imminent.) Stakeholders’ reactions to the filing rolled in this week.  

MidAmerican Energy protested MISO’s filing, saying the marginal accreditation style would lower dispatchable resources’ values across its fleet with little explanation and result in undue discrimination to renewable energy. The company said examples MISO provided earlier to stakeholders to illustrate capacity values showed “accreditation values were well below the resource’s actual performance.” 

“Compounding this issue, MidAmerican has been unable to recreate … MISO’s results or get information from …MISO that explains why MISO’s results are vastly different from actual operations,” it wrote to FERC.  

Consumers Energy likewise said MISO’s accreditation proposal suffers from a lack of data transparency around class averages. It said it was impossible to understand why MISO set a pumped storage class average of 98% in the summer and fall seasons but just 50% in winter and 67% in spring for a consistently dispatchable resource.  

MISO’s accreditation would use a two-step process. First, MISO would calculate a probabilistic, resource-class average accreditation using its loss-of-load expectation analysis. MISO then plans to tailor resource class-level accreditations to individual generators based on their availability during both normal operating conditions and high-risk hours, including hours with low margins or emergency events in place. MISO plans to give greater weight to hours that contain emergency or near-emergency conditions in the ensuing accreditation.  

Most resources’ credits would shrink under the new accreditation. Resources would be divided by fuel type: gas, coal, combined-cycle hydro, nuclear, energy storage, pumped storage, run-of-river, biomass, wind and solar. 

A joint protest from Sierra Club, Natural Resources Defense Council, Sustainable FERC Project, Fresh Energy and Clean Wisconsin argued that because MISO’s loss-of-load expectation analysis features heavily in its accreditation and would have “outsized” impacts, MISO should have included its loss-of-load study methodology for scrutiny in its filing. 

A group of seven transmission-dependent Midwestern utilities criticized MISO’s accreditation design for relying on its self-described imperfect loss-of-load expectation analysis and inappropriately grouping dual-fuel combustion turbines into the same resource class as single-fuel counterparts. They called the design “not yet ready for prime time” and asked FERC to reject it.  

The MISO Cities and Communities Coalition — a collection of local governments within MISO focused on decarbonization including Minneapolis, New Orleans, St. Louis and Des Moines — said it worried MISO’s probabilistic accreditation would stymie clean energy targets. The coalition said MISO hasn’t provided enough detail around how it will treat energy storage in modeling and dispatch for accreditation purposes. It also said it worried the accreditation devalues solar generation’s contribution by not recognizing solar would subdue an afternoon peak and send it later into the evening, thus reducing reserve requirements on all resources.  

Entergy and Cleco also argued that elements are missing from MISO’s proposal, including how MISO would distribute planned outages across resource classes in probabilistic modeling, how MISO would factor resource deliverability into accreditation and how MISO would model deployment of energy storage resources. The two said FERC should order MISO to make another filing to fill in those blanks.  

Alliant Energy said while it “understands the need for changes to MISO’s markets in the face of the evolving resource mix,” it asked FERC to be open to delaying MISO’s rollout beyond the 2028/29 planning year.  

Clean energy proponents — Advanced Energy United, the American Clean Power Association, Clean Grid Alliance, Invenergy, NextEra Energy Resources, the Solar Energy Industries Association and the Southern Renewable Energy Association — jointly asked FERC to reject the filing. They argued MISO’s accreditation proposal would “unrealistically undervalue certain resources below their actual and likely contributions to system needs.” They also said MISO’s filing lacks detail and argued the set of resource classes aren’t nuanced enough and omit “technological and geographical distinctions” that lower capacity contributions. 

On the other hand, DTE Energy said MISO’s accreditation is a “resource-agnostic approach that appropriately shifts resource accreditation to focus on time periods of greatest reliability risk.” Constellation Energy also said MISO’s approach would help address operating challenges wrought by an evolving resource mix, extreme weather and load growth.  

The Michigan Public Service Commission said it supported MISO’s move to a probabilistic accreditation, calling it a “culmination of historical incremental changes, along with rapidly changing conditions in recent years such as continuing resource transitions, rise in extreme weather events, shifting load patterns and the reduction of reserve margins.” The commission said the accreditation is an honest attempt to “address the growing misalignment of the current system, which fails to properly represent risk, and the reliability of resources in the context of newly developing risks.”  

The Organization of MISO States itself was more cautious with its backing. It said while it “broadly” supported the accreditation, it emphasized MISO’s three-year transition period is essential, particularly in understanding how the direct loss-of-load approach would affect not only accreditation, but how MISO would divvy up reserve margin requirements among load-serving entities (LSEs).  

MISO is set to apply its probabilistic model not only to resources participating in its capacity auctions but extend it to its calculation of planning reserve margin requirement, which it divides into responsibilities among load-serving entities.  

However, MISO’s filing did not detail how it would use the probabilistic model to allocate its planning reserve margin requirement among LSEs, leaving that to a later, separate filing. Today, MISO metes out the requirement on a load-ratio share.  

“Given the significant changes the (direct loss-of-load) methodology could impose on the resource planning efforts by LSEs and their respective retail regulators, and given the need for further discussions around modeling improvements, MISO’s proposed three-year transition period is an essential component of MISO’s filing,” OMS wrote. It asked that MISO publish semi-annual status reports on how the probabilistic model would influence reserve requirements so LSEs can make better generation investment decisions.  

Arkansas Electric Cooperative Corp. also expressed concern the new accreditation would introduce “dramatic changes to the capacity allocation process and increased financial burden for a significant number of LSEs.”  

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MISO Starting from Scratch on New Schedule for Reviewing Expedited Tx Projects

CARMEL, Ind. — MISO is scrapping an earlier suggestion that it accept and study expedited transmission project requests quarterly. 

Now the grid operator is turning to its stakeholders for ideas on how to handle mounting requests for accelerated approval.   

Senior Manager of Expansion Planning Amanda Schiro said while batching expedited project review requests into quarterly studies works for MISO internally, members have indicated a quarterly schedule likely would result in missed construction deadlines. However, Schiro said MISO still hopes to put a “more defined time frame” on expedited request submittals and cut down on receiving them “whenever.”  

“Time is truly the driving factor we need to take into account,” Schiro said during a May 1 Planning Subcommittee meeting. “We want to continue to meet the needs of this community.”  

Schiro also said members had concerns that quarterly groupings that contain especially large transmission projects would hold up other projects lining up for expedited treatment.  

MISO late last year said it’s become inundated with expedited review requests as load flourishes and that it likely needs to rethink its approach to transmission projects that cannot wait until the usual December board approval to begin construction. (See MISO to Re-examine Schedule for Reviewing Expedited Tx Projects.) The grid operator suggested this year a quarterly schedule might solve the problem.  

MISO currently accepts and studies expedited projects reviews every month as they come in, a schedule Schiro said is difficult to manage. The RTO conducts individual studies on the expedited requests to confirm the projects won’t result in reliability violations before allowing them to proceed ahead of the annual Transmission Expansion Plan cycle.  

Schiro asked stakeholders to decide whether they would back an every-other-month timetable for studying expedited reviews and if they would support adding a requirement that developers pay study deposits and fees alongside their requests for expedited treatment. 

“Part of putting a fee in place would allow MISO to supplement our staff to accommodate all the requests coming in,” she explained.  

Schiro also asked stakeholders how they feel about removing the requirement that the Planning Advisory Committee’s approval of expedited reviews occur strictly during meetings.  

“Are there ways we can engage with the PAC outside of a meeting?” Shiro asked.  

Schiro said she didn’t think the PAC has ever rejected a MISO study finding of no reliability harms for an expedited review. However, WPPI Energy’s Steve Leovy said the PAC in recent years hasn’t been granting explicit approval of expedited reviews, with study results merely posted with meeting materials and not discussed during meetings.  

Schiro said MISO views a lack of objections from PAC members as approval of its expedited review findings.  

MISO and stakeholders will continue to mull changes to the expedited project schedule at upcoming Planning Subcommittee meetings.  

NextEra Asks MISO to Study New Load and Generation Duos

Additionally, the Planning Subcommittee this year will address NextEra Energy’s request that MISO work out a method to study new load and generation concurrently when they’re proposed as a double act.  

NextEra Energy approached MISO publicly in April and asked it to craft specialized rules in its interconnection queue to recognize when new generation is entering the queue for the sole purpose of supporting a specific new load, such as a large data center.  

NextEra pointed out that large industrial loads increasingly want new renewable energy sources onsite, but MISO’s interconnection rules aren’t designed to account for them in tandem. NextEra said MISO and its transmission owners take stock of load growth through the annual Transmission Expansion Plan (MTEP), with that process separate from MISO analyzing new generation through its interconnection queue. NextEra said that to sync up generation and load dependent on one another, either generation owners must secure their interconnection agreements before MTEP studies kick off that year or the owners of the new load in question must get their approval to join the system before queue studies begin.  

NextEra said the uneven process results in either the load or generator being subject to network upgrades without knowing the upgrade costs the other will face. The company said MISO should allow for co-located load and generation behind the same point of interconnection and recognize that “neither will show up alone if the other is not built.”  

NextEra asked that MISO devise a way to study the load a generator is designed to support alongside the generator itself in its interconnection queue process. The company also asked that the interconnection agreements MISO issues to such generation be contingent on the load showing up.  

Stakeholders at the May 1 Planning Subcommittee meeting said the need to address growing load is timely and the topic should be placed on the subcommittee’s calendar as soon as possible. WEC Energy Group’s Chris Plante said the issue overlaps with the need for improvements with expedited transmission project reviews, because many expedited reviews are compelled by new load. 

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WEIM Q1 Benefits Report Adds to NW Cold Snap Debate

CAISO’s first-quarter Western Energy Imbalance Market benefits report offers another footnote to the debate over the market’s role in responding to the January deep freeze that brought parts of the Northwest to the brink of rolling blackouts. 

“The Western Energy Imbalance Market’s cumulative benefits rose to $5.49 billion during the first three months of this year, while also demonstrating the value of regional coordination by helping maintain system reliability during a January cold snap that stressed grid conditions in the Northwest,” the ISO said in a press release accompanying the April 30 report. 

The report shows the WEIM produced $436.3 million in economic benefits for its participants during the first three months of 2024, a 4% increase from a year earlier and a new first-quarter record. 

That bump was partly from the addition last spring of three new members, including the Avangrid balancing authority area in the Northwest, El Paso Electric and the Western Area Power Administration Desert Southwest Region (WALC). The market now includes 22 participants representing over 80% of the load in the West — including CAISO itself. 

The unsettled debate over the Northwest cold snap began to take shape shortly after the Jan. 12-16 weather event triggered five energy emergency alerts (EEAs) in the Northwest, including one critical EEA 3 in Idaho Power’s territory. 

The dispute has centered on disagreements over how vital CAISO and the WEIM were in supporting the Northwest during the event, with some parties contending that the region’s utilities relied heavily on imports from the Desert Southwest and Rockies region to support operations, while others argued the ISO and its real-time market were key to facilitating those transfers. 

The debate has become something of a proxy for the broader competition for market participants between CAISO’s Extended Day-Ahead Market (EDAM), which builds on the WEIM, and SPP’s Markets+ day-ahead offering, which has attracted strong interest in the Northwest and Arizona. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.) 

The Economics of Rebalancing

The quarterly benefits report adds modestly to the 80 pages of analysis CAISO released March 6 on the WEIM’s January performance. 

That paper focused on how the WEIM helped manage energy flows throughout the West during the cold snap, attempting to answer critics arguing that the ISO’s status as a net importer of energy during the five-day event offered evidence that the Southwest was the real source of the Northwest’s rescue. The analysis noted that the WEIM transfers into CAISO were not the product of limited supply within the ISO but the result of the “economic displacement and opportunities optimized by the market and bounded by the transmission and transfers availability in the wider footprint.” (See NW Freeze Response Shows WEIM Value, CAISO Report Says.) 

The benefits report riffed off that theme. 

“During the winter conditions experienced in January 2024, the Western Energy Imbalance Market economically rebalanced supply across the West to meet increasing demand as real-time conditions evolved over the Martin Luther King Jr. Day weekend,” it said. 

On the surface, the data contained in the report seems to back up that contention, even if it doesn’t drill down into specific days. The data show that in January, the CAISO BAA facilitated 350,271 MWh of WEIM wheel-through transfers, a 46% increase from the same month a year earlier. The ISO’s net exports for the month also increased 46%, to 363,837 MWh, while net imports decreased by 21% to 353,353 MWh. 

The areas with the next-largest volumes of January wheel-throughs were Arizona Public Service (158,625 MWh), WALC (130,870 MWh) and PacifiCorp’s West BAA (92,240 MWh). 

The second-largest net importer of energy through the WEIM that month — behind CAISO — was British Columbia’s Powerex at 336,809 MWh (compared with 177,954 MWh in January 2023), as the province and other parts of the Northwest dealt with record electricity demand during the cold snap. 

“The market identified least-cost solutions within the wider WEIM footprint, transferring lower-cost electricity from the Southwest into California. These transfers allowed exports scheduled in the day-ahead and hour-ahead markets to flow to the Northwest, replacing more expensive generation while managing congestion on key transmission lines,” the report said. 

According to the report, PacifiCorp earned the largest share of WEIM benefits during the first quarter, at $73.83 million, followed by CAISO ($54.33 million), the Los Angeles Department of Water and Power ($46.80 million), Puget Sound Energy ($25.88 million) and Powerex ($24.83 million). 

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PSEG Sees New Market for Nuclear in AI, Data Centers

Public Service Enterprise Group is looking to use excess capacity at its three South Jersey nuclear generators to provide clean energy for data centers and artificial intelligence development projects that could be sited in the state in the future, CEO Ralph LaRossa said in the company’s first-quarter earnings call April 30. 

The proposal is part of the company’s ongoing effort to “pursue potential investment opportunities for future regulated growth,” LaRossa said. Other possibilities include doing work to upgrade the state’s transmission lines in preparation for offshore wind energy, he said. 

PSEG is the majority co-owner of Salem Generating Station Units 1 and 2, with Constellation Energy, and is the sole owner and operator of the Hope Creek plant. It recently informed the Nuclear Regulatory Commission that it intends to seek operating license extensions that would add an additional 20 years to the plants’ life. (See PSEG Plans for 80-year Nuclear Generation in NJ.) 

LaRossa said the nuclear fleet is “pursuing multiple growth paths with modest capital spending needs” and that thermal upgrades planned for one of the Salem units “could potentially add up to 100 MW of additional capacity.” That capacity could “qualify for clean hydrogen tax credits,” he said, created by the Inflation Reduction Act that in some circumstances can be awarded to nuclear plants that produce hydrogen. 

“Beyond these opportunities in nuclear, there has been discussion lately about the potential for direct power sales to data centers from our three-unit Artificial Island site,” he said, referring to where the nuclear plants are located. At present, the site has additional space available. 

“We’ve had discussions related to both sides of the meter in recent months,” LaRossa said. They have included “new business inquiries at PSEG for midsized data center construction of approximately 50 to 100 MW and behind-the-meter inquiries for co-located facilities that prioritize highly reliable, carbon-free baseload power from existing facilities, all without the challenges faced by non-dispatchable generation,” such as wind and solar. 

“This data center opportunity has the potential to create a nexus between economic development and [state] energy policy,” LaRossa said. 

Offshore Infrastructure

In a separate issue, LaRossa said the company is still waiting for guidance from the U.S. Treasury on how it can apply for production tax credits, also available under the IRA, to support the three nuclear plants.  

PSEG and Constellation in November withdrew from New Jersey’s Zero Emission Certificate (ZEC) program, which had awarded subsidies of $300 million a year since 2019 to keep the plants open. PSEG said it would instead focus on seeking federal tax credits.  

The companies’ withdrawal from the program has effectively shut it down, with the Board of Public Utilities approving an order in February that will end the fees customers have paid to fund the subsidies. (See NJ Closes Nuclear Subsidy Process as PSEG Looks to Feds.) 

The three plants generated 42% of the electricity produced in the state in 2022 and are key to Gov. Phil Murphy’s goal of reaching 100% clean energy by 2035. In addition, Murphy has outlined plans to create an AI hub at Princeton University, and on April 11, he spoke at the state’s first AI Summit. 

LaRossa said that as part of the company’s search for “competitive transmission solicitations in the Mid-Atlantic region,” it submitted bids in April to the BPU’s “pre-build infrastructure solicitation, for which the selected projects are expected to be announced in the second half of 2024. The solicitation is designed to award projects that can connect offshore wind farms to the grid through the onshore infrastructure approved in October 2022. (See NJ BPU OKs $1.07B OSW Transmission Expansion.) 

In addition, PSEG is evaluating a possible bid for New Jersey’s second solicitation for offshore transmission infrastructure under the second State Agreement Approach with PJM, he said. The company is looking to participate in “PJM’s 2024 Regional Transmission Expansion Plan Window One solicitation, which is expected to include the impacts of higher load growth forecasts that have been influenced by increased electrification expectations and data center load growth throughout PJM.” 

PSEG’s first-quarter results for 2024 fell short of those in 2023. The company reported net income of $532 million ($1.06/share), compared with $1.287 billion ($2.58/share). Non-GAAP operating earnings for 2024 were $657 million ($1.31/share), compared with $695 million ($1.39/share) in the same period in 2023. 

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SPP Markets+ Tariff Sparks Concerns for PacifiCorp, NV Energy

Although PacifiCorp has formally committed to joining CAISO’s Extended Day-Ahead Market (EDAM), the utility is still voicing concerns about a competing day-ahead market, SPP’s Markets+, in a FERC filing. 

In its April 29 comments, PacifiCorp asked FERC to reject the proposed Markets+ tariff, but allow SPP to refile it without the tariff’s “Markets+ transmission contributors” transmission availability option. The utility said the option “purportedly empowers transmission customers to ‘contribute’ their transmission rights on nonparticipating systems.” 

In a separate filing, NV Energy also expressed concerns regarding the “transmission contributors” option. 

But other comments filed by the April 29 deadline — including those from three Arizona utilities and a member of the Arizona Corporation Commission — supported the Markets+ tariff. 

Transmission Providers, Contributors

PacifiCorp became the first Western entity to formally commit to one of the two competing day-ahead markets April 26 when it signed an implementation agreement with CAISO for EDAM. (See PacifiCorp Fully Commits to CAISO’s EDAM.) 

But as a major Western grid operator, PacifiCorp is concerned about potential impacts of transmission provisions in Markets+. 

Under the proposed tariff, one source of transmission would be from transmission service providers who sign a Markets+ agreement. Transmission could also come from market participants who contribute their rights from transmission providers who aren’t Markets+ participants. 

But it’s unclear how those so-called Markets+ transmission contributors “would be entitled to make such decisions on behalf of transmission providers,” PacifiCorp said. 

In addition, allowing transmission customers to potentially offer transmission rights to different day-ahead markets “is uneconomic and inefficient,” PacifiCorp said, and could potentially undermine EDAM operations. 

NV Energy said it has asked for clarification on the issue of contributors’ transmission rights. Although SPP has proposed a “service flow constraint” respecting transmission contributors’ and transmission service providers’ capabilities, the tariff “is not clear as to the entity that can establish the Service Flow Constraint and ‘carve out’ this transmission capacity from the market,” NV Energy said. 

NV Energy also urged SPP to keep working to ensure interoperability between Markets+ and Western Power Pool’s Western Resource Adequacy Program (WRAP). 

“SPP should confirm that the Markets+ tariff maintains the ability of the transmission service providers participating in Markets+ to provide support to WRAP wheel-out and wheel-through transactions on a firm basis, even if the need arises after the close of the day-ahead market run,” NV Energy said.  

Arizona Support

Three Arizona utilities — Arizona Public Service (APS), Tucson Electric Power (TEP) and Salt River Project (SRP) — supported the Markets+ tariff, pointing to the proposal’s independent governance and the stakeholder-driven development of the tariff. 

They view the requirement that Markets+ participants be WRAP members as another plus. 

“The defined RA standard for WRAP ensures Markets+ programs will maintain adequate resources,” TEP said in its filed comments. “The requirement also establishes uniformity, which imparts a high degree of simplicity and transparency for resource adequacy in Markets+.” 

The utilities’ comments echo those in an April letter to SPP from 26 entities supporting Markets+. (See 26 Western Entities Signal Continued Support for Markets+.) 

Commissioner Nick Myers of the Arizona Corporation Commission also weighed in to support Markets+ “as a market option in the Western region.” 

Myers said that as a member of the Markets+ State Committee (MSC), he could contribute to discussions on addressing different greenhouse gas policies within the market. 

“The Markets+ tariff strikes a balance by adopting a market design that enables states with GHG regulations to meet their identified goals without holding market participants in other states to the same GHG policy requirements,” Myers said in filed comments. 

SPP filed its proposed Markets+ tariff with FERC on March 29 and asked FERC to issue an order on the tariff by July 31. (See SPP Files Proposed Markets+ Tariff at FERC.) 

SRP was among commenters who supported that time frame. 

“Approval on this timeline will provide Salt River Project and potential market participants certainty regarding market rules and allow the timely development and testing of the systems and processes necessary to implement Markets+,” SRP said in filed comments.