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November 14, 2024

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NERC Board of Trustees/MRC Briefs: Feb. 14-15, 2024

HOUSTON — NERC Board Chair Ken DeFontes will hold the gavel for one more year after the organization’s Board of Trustees re-elected him at its quarterly open meeting Feb. 15. 

The board chose Suzanne Keenan as vice chair and chair-elect, replacing current vice chair George Hawkins. Hawkins will continue to serve on the board, along with fellow trustees Larry Irving, Sue Kelly and Rob Manning, all of whom were elected to new three-year terms at the Feb. 14 open meeting of the ERO’s Member Representatives Committee. 

NERC to Leave Atlanta Office

NERC CEO Jim Robb reported in his opening remarks that the organization has opted not to renew the lease on its Atlanta office when it expires in 2025. Citing positive industry responses to the ERO’s renovated office in Washington, Robb said NERC will step up its use of that space and of regional entities’ facilities. While NERC will continue to hold meetings and events in Atlanta, Robb said it is in talks to use a local coworking space. 

NERC’s next board and MRC meetings will be at the Washington office in May, following a hybrid format in which only trustees and MRC participants attend in person and observers join remotely. 

Cold Weather Standard Accepted

As the board voted on the new reliability standard EOP-012-2 (Extreme cold weather preparedness and operations), DeFontes applauded “the hard work on the part of the entire industry” that brought the standard to this point. 

EOP-012-2 has been in development since February 2023, when FERC approved its predecessor EOP-012-1 with orders to NERC to draft a new standard within a year addressing its shortcomings. Getting the project to completion proved challenging, however. Industry stakeholders rejected the proposed standard in multiple ballot rounds, raising concerns among NERC’s leadership that FERC’s deadline might be missed. 

The impasse reached a peak at the board’s last meeting in December, when DeFontes warned that the board might exercise its authority under Section 321 of NERC’s Rules of Procedure to approve a standard without a successful ballot. But this proved unnecessary after stakeholders approved the standard at its third ballot round in January with an 81% segment-weighted vote for passage. (See Industry Approves New Cold Weather Standard in Final Vote.) 

Along with the cold weather standard, the board also agreed to submit for FERC approval a new set of definitions for NERC’s glossary affecting multiple standards. The terms are the result of Project 2022-01 (Reporting ACE definition and associated terms) and were approved in an industry ballot that concluded Dec. 20. 

Soo Jin Kim, NERC’s vice president of engineering and standards, told trustees the project was started because the Eastern Interconnection was “experiencing more frequent events with regard to area control errors (ACE)” compared to the Western Interconnection. 

The Reliability and Security Technical Committee’s Resources Subcommittee determined the current definition of Reporting ACE in NERC’s glossary did not allow the Eastern Interconnection to implement automatic time error correction processes. Kim said the changes will allow all interconnections to use time error correction and clarify what information should be used in calculating Reporting ACE. 

Stakeholders Discuss ROP Changes

According to the agenda, trustees would have voted on proposed changes to NERC’s Rules of Procedure relating to registration of inverter-based resources after the standards actions. But DeFontes informed attendees that because of stakeholder feedback regarding this item, the board decided to host a discussion of the proposal instead. He said the discussion will inform the board’s vote on the measure “a week or two from now.” 

NERC developed the proposed ROP changes last year as Stage 1 of its three-stage registration process, which FERC approved in May 2023 (RD22-4). They mainly will update the definitions of generator owner and operator to include entities with IBRs connected to the grid. 

Howard Gugel, NERC’s vice president for compliance assurance and registration, opened the conversation by highlighting a “minor victory” in the fact that “everyone in here agrees [about] who needs to be registered,” citing widespread agreement on the proposal that entities operating IBRs with aggregate nameplate capacity of at least 20 MVA, working through a common point of connection with a voltage of at least 60 kV, should be considered part of the bulk electric system and subject to NERC standards. 

However, he also acknowledged the concerns of many stakeholders that the proposed definition would be overly broad and disruptive to their businesses. Exelon’s Jennifer Sterling, for example, said many worried the proposed definitions would affect enforcement of standards and apply to utilities that they were not intended to. 

“Being the engineer that I am, I was concentrating on the numbers and focused on that victory, and not realizing that there were some other key conversations that really needed to occur,” Gugel said. 

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NJ Closes Nuclear Subsidy Process as PSEG Looks to Feds

New Jersey’s Board of Public Utilities shut down its third offering of nuclear subsidies after PSEG Nuclear and Constellation Energy Generation, which operate the state’s three nuclear plants, opted to not apply for state subsidies as they seek federal support. 

The board’s unanimous vote Feb. 14 quietly ended a process to determine support for the three South Jersey nuclear plants — Hope Creek, Salem 1 and Salem 2 — that in the last subsidy process triggered a contentious debate over whether the plants needed the financial break to remain in existence. 

The Zero Emission Certificate (ZEC) program provides subsidies to nuclear power plants at risk of closure so they can remain open to generate carbon-free power. A ZEC in New Jersey compensates the nuclear plant for generating one megawatt-hour of electricity, with funds collected by the utilities from ratepayers at a rate of $0.004 per kilowatt hour (kWh). 

In the 2022 discussions to decide subsidies for the current three-year period, which covers 2023 to 2025, critics argued that the plant operators did not need the maximum possible subsidy of $300 million to remain in business. The BPU, which under the law could have reduced the amount, nevertheless awarded the maximum. 

The BPU said in the Feb. 14 order that the third offering, which the board opened Aug. 21, would be closed because there were no applications once PSEG and Constellation withdrew. The offering would have awarded subsidies from June 2025 to May 2028. 

Doug O’Malley, director of Environment New Jersey, called the move a “win for ratepayers” that means the funds that might have gone to the nuclear plants in the future now can support other forms of clean energy generation. 

“We do need to obviously move towards an energy future that isn’t necessarily dependent upon” aging nuclear plants, he said. 

Maintaining Options

PSEG — the sole owner and operator of the Hope Creek plant and the operator and majority co-owner of Salem 1 and Salem 2 plants — submitted a notice of intent Aug. 21 to file for ZECs for the three plants. So did Constellation Energy, the minority co-owner. 

But both companies withdrew from the ZEC process. In a Nov. 22, 2023, letter to the board, PSEG said its earlier notice of intent was “filed to preserve PSEG’s rights” while it pursued federal production tax credits (PTC) due to be awarded to nuclear power generators under the 2022 Inflation Reduction Act. 

PTCs create a credit of $15/mWh for electricity produced by existing nuclear plants, beginning at the start of 2024 and running through 2032, according to the Nuclear Energy Institute. New Jersey paid $10/MWh in its two awards. 

PSEG said the federal program would “impact” the state ZEC program, and at the time the utility filed the notice of intent, it was awaiting “further clarity” from the Treasury Department of final rules regarding implementation of the PTC. 

“While those rules have still not been issued, PSEG has determined in light of all relevant facts and circumstances, including the purpose of the PTC established by Congress for qualifying nuclear facilities, that at this time the company does not intend to file applications in this (New Jersey’s) proceeding with respect to its three nuclear generation units,” the letter said. 

Constellation submitted a similar letter to the BPU on Nov. 30. 

PSEG released a statement Feb. 15 saying that though the Treasury rules for the PTC program still have not been issued, the company “has confidence that the PTC will proceed as intended and sufficiently support the nuclear generating units.” 

The statement added that the company remains committed to “providing carbon-free, reliable and affordable sources of power generation and will revisit the need for ZECs if federal support of the industry is insufficient.” 

Former CEO Ralph Izzo, who stepped down in 2022, suggested at least twice before he left that the company was looking to the federal government for support for the nuclear plants, adding in May 2022 that it would “reduce the pressure on New Jersey customers.” (See PSEG Sees Potential $3B OSW Transmission Spending.) 

Net-Zero Reliance

Nuclear-generated electricity accounts for about 35% of the state’s power at present, with solar power contributing 7%. The state has no wind power yet online. State officials and environmental groups say maintaining the nuclear plants’ operations will be key to helping the state achieve the goal set by Gov. Phil Murphy (D) of 100% clean energy by 2035. 

The Legislature created the program in 2018, and the board in 2019 awarded ZECs totaling $300 million to the three South Jersey nuclear plants in the first award under the law. (See NJ Approves $300M ZECs for Salem, Hope Creek Nukes.) 

In the next award in 2022, covering the period from June 2023 to May 2025, state law allowed the BPU to set the size of the award. But PSEG said in discussions leading to the award that it would close the plants unless it received the $10/MWh rate, which is the maximum the program allows and the amount the BPU awarded. 

That sparked criticism from the New Jersey Division of Rate Counsel, the state’s consumer advocate, and environmental activists, some of whom said PSEG had exploited its market dominance to extract an unnecessarily large payoff. Some BPU commissioners also expressed concern at the size of the award but said the environmental and financial cost of not awarding the ZECs would be too great. (See New Jersey Nukes Awarded $300 Million in ZECs.) 

Rate Counsel Opposition

After the award, the Division of Rate Counsel filed an appeal of the awards to the Appellate Division of the state Superior Court, which rejected the claim in a Dec. 4 ruling.  

The rate counsel argued the BPU failed to do a thorough review of the case and disregarded “expert opinion that the three plants miscalculated their revenues, costs and risks, whereas a correct accounting demonstrated the plants did not need subsidization.” The Appellate Division concluded the board’s findings that underpinned the award were supported by “substantial evidence.” 

Brian O. Lipman, director for the Division of Rate Counsel, welcomed the closure of the ZEC process for another three years. 

“It’ll be good news for ratepayers, especially the commercial/industrial in the state because this was a major impact on their bill,” he said, and reiterated the belief expressed in the court arguments that the plants did not need subsidies to survive. 

“I do think that to the extent subsidies are needed, this is more of a federal issue, which should be dealt with at the federal level,” he said. “Ratepayers should not be paying subsidies for nuclear power plants in New Jersey.” 

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State Regulators Debate Reliability and Transmission at House Hearing

House members and their state regulator witnesses split Feb. 14 over how much an expanded transmission grid could enable a reliable transition to a low-carbon future.  

“Threats to electric grid reliability are growing due to environmental regulations, policies from state legislatures and agencies, bans on fossil fuel generation, and market distortions,” said Rep. Jeff Duncan (R-S.C.), chair of the House Committee on Energy & Commerce’s Subcommittee on Energy, Climate and Grid Security. “These factors are contributing to premature retirement for most of our reliable and dispatchable resources. Because of the increasingly interconnected nature of the grid, policy decisions that affect grid reliability have a much wider impact than ever before.” 

Rep. Scott Peters (D-Calif.), who also sits on the subcommittee, has introduced legislation to help address some of those reliability concerns by requiring minimum transfer levels between regions. (See Hickenlooper and Peters Introduce Big WIRES Act.) He agreed with Republicans on the committee that policymakers need to address resource adequacy with growing demand from electrification, data centers and new industries. 

“Multiple analyses recently from MIT and Columbia have shown that the Big Wires Act, which I and Senator Hickenlooper introduced, would save customers hundreds of millions of dollars while keeping the lights on during natural disasters and other challenges,” Peters said. “These costs and reliability benefits are driven by the ability of high-demand regions to use energy from other regions that don’t need it at that time.” 

Duncan doubted that increased transmission could be a cure-all for the country’s reliability woes, calling instead for maintenance ofexisting dispatchable generation. 

“Systems must be overbuilt to ensure there’s power when the sun is down and when the wind isn’t blowing,” Duncan said. “Building more transmission also raises utility costs for American ratepayers, even if those ratepayers may not directly benefit from the added transmission.” 

California and New England have adopted similar policies driving their grids to zero out emissions, but both rely on imports from other areas, and both have some of the highest electricity prices in the country, Duncan added. 

Georgia Public Service Commissioner Tricia Pridemore touted the reliability of her state’s vertically integrated structure.  

“Georgia is in need of more power than ever before,” she said. “Our market structure makes us more energy-secure than other regions; we have the authority to instruct utilities to construct generation and build transmission. The state of Georgia holds a compact with a vertically integrated utility, and they must generate what our state consumes.” 

While the Vogtle nuclear plant’s cost overruns might have made a lot of headlines and increased her consumers’ bills, she said that the Peach State still has rates 10% below the national average.  

Peters asked Pridemore whether Georgia would exclusively rely on its own power plants, given that it is connected to five other regions of the Eastern Interconnection. 

While Georgia is connected, the regulatory compact the state has with Southern Co.’s Georgia Power requires it to produce all of the power the state needs, she said. 

“You mentioned blackouts and forced outages earlier,” Pridemore said. “You can look at the last three winter storm incidents, and the number of blackouts and outages that we had were so minimal. They were just those that were caused by downed trees and localized events.” 

Pridemore called for easing regulation of pipelines, and Peters asked whether she thought that effort should be extended to transmission. Pridemore answered that she is “satisfied” with how Georgia manages electric transmission. 

Colorado, the only state with a carbon policy at the hearing, was represented by Keith Hay, senior director of policy in the state Energy Office, who said the state’s goals are not too difficult to achieve with the resources it can access. 

“Our modeling shows that under the business-as-usual approach, which is the lowest-cost scenario that meets a 2040 load growth of 40%, the Colorado grid can achieve a roughly 94% reduction in greenhouse gas pollution,” Hay said. “It does this by adding significant amounts of wind, solar and batteries while retaining a gas generation fleet that is approximately the size of today’s.” 

While the gas plants will still be there, their capacity factors would drop significantly over time according to the model: By 2030, only one natural gas unit approaches a 20% capacity factor, and by 2040, natural gas will produce just 2% of the state’s electricity, he added. 

“The analysis strongly indicates that expanded transmission capacity, both in-state and interregional, which will enable reaching regions of high renewable potential and allowing access to energy from across diverse geographic areas, will be important to reliably meeting Colorado’s electric needs,” Hay said. 

Indiana has seen coal fall from 90-95% of its electricity 20 years ago to about 45% today, with the rest coming from natural gas, nuclear, wind, solar and other fuels, said Utility Regulatory Commission Chair Jim Huston. While Colorado has found no major issues in moving to a net zero future, Indiana has said it would face difficulty meeting the requirements of EPA’s power plant rule.  

“Our concerns included a focus on the proposed rules’ unrealistic timing, particularly in the context of the utilities’ state-sanctioned and regulator-reviewed integrated resource plans,” Huston said. “It is not obvious that the proposed environmental benefits outweigh the other pillar considerations that state regulators must consider to ensure safe, reliable service at affordable rates.” 

Arizona also has seen cost issues from shutting down fossil fuel-fired plants early, said Corporation Commissioner Nick Myers. 

“Many of the challenges we face moving forward with regard to reliable generation center around early forced retirement of coal plants without adequate replacement,” Myers said. “Personally, it pains me to have to approve accelerated cost recovery for early shutdown of coal plants, while at the same time authorizing recovery on new purchase power agreements.” 

The replacement generation usually has to come with backup natural gas and transmission, which Myers said makes its all-in costs higher. The transmission also presents its own roadblocks, as Arizona had to deal with multiple iterations of the SunZia Transmission project and its 16-year development journey, marred by lawsuits and red tape. (See SunZia Project Wins Final Approval, Signs Offtakers.) 

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Caltrans Signs $127M Deal for Hydrogen-powered Trains

California is spending $127 million to buy six hydrogen-powered passenger trains, building on an earlier order of four of the zero-emission vehicles from Stadler Rail.

The California Department of Transportation (Caltrans) announced the latest purchase Feb. 14. It is a follow-up to the $80 million contract with Stadler Rail, signed in October, for four hydrogen-powered passenger trains.

The contract includes options for up to 25 additional hydrogen trains on top of the first four.

The first trains are expected to start paid service in 2027. They will run mainly between Merced and Sacramento but may also be used in demonstrations across the state.

“California continues to lead the way to a cleaner, more connected transportation system,” California Transportation Secretary Toks Omishakin said in a statement. ‘By expanding our fleet of hydrogen-powered passenger train sets, we are showing we are serious about deploying innovative and sustainable transportation options for the people of this state.”

Omishakin said previously that the hydrogen trains will complement California’s future electrified high-speed rail line. The first hydrogen trains will run along an expansion of the existing Altamont Corridor Express (ACE) and Amtrak San Joaquin routes that will eventually connect with high-speed rail between Merced and Bakersfield.

Funding for the hydrogen trains is coming from Gov. Gavin Newsom’s $10 billion zero-emission vehicle package. The multiyear package includes $407 million for the California State Transportation Agency to buy or lease clean bus and rail equipment and infrastructure.

The multicar trains from Stadler will use hydrogen fuel cells and won’t need a locomotive.

The design, which Stadler calls the Fast Light Intercity and Regional Train (FLIRT), makes the trains lighter, less expensive and more efficient than traditional locomotive-hauled coaches, Caltrans said.

Stadler initially worked with the San Bernardino County Transportation Authority (SBCTA) on developing the hydrogen-powered trains. That work led to Caltrans’ purchase in October of what the agency called the first zero-emission, hydrogen intercity passenger trains in North America.

Stadler is a Swiss company with a U.S. division based in Salt Lake City. Stadler said the new hydrogen train has been tested extensively in the U.S. and Switzerland.

Caltrans’ purchase agreement with Stadler in October came just before the U.S. Department of Energy announced that California will receive up to $1.2 billion as one of the nation’s seven potential regional hydrogen hubs. (See DOE Designates Seven Regional Hydrogen Hubs.)

Among the goals of the California hub are to decarbonize public transportation, heavy-duty trucking and port operations.

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NEPOOL Reliability Committee Briefs: Feb. 14

ISO-NE provided additional detail in response to stakeholder questions about how the RTO plans to model oil and gas resources as part of its ongoing Resource Capacity Accreditation (RCA) project at the NEPOOL Reliability Committee (RC) on Feb. 14.

The RTO explained the Resource Adequacy Assessment (RAA) modeling approach to the RC in January. (See ISO-NE Details Resource Modeling Plans for Capacity Accreditation.) Stakeholders followed up with feedback related to the modeling of imports from Saint John LNG, the uncertain future of the Everett Marine Terminal (EMT) and variability in the amount of gas available to generators.

Fei Zeng of ISO-NE said the current modeling approach “accounts for the EMT impact in a balanced way, given its uncertain future status. The adjustments made to historical availability to generation do not contemplate a single scenario of EMT either continuing operation or retired; therefore, fewer additional adjustments will be needed when EMT status becomes known.”

If EMT is not retained, ISO-NE will adjust its modeling to consider how the loss would impact local gas distribution companies, and the knock-on effects this would have on gas available for generators, Zeng said. If EMT is retained, ISO-NE will assess how much “additional available gas to generation EMT can provide through the remaining capacity headroom” on the region’s major gas pipelines.

Massachusetts’ two largest gas utilities recently announced agreements with Constellation, the owner of EMT, to keep the facility open through May of 2030, pending approval of the Massachusetts Department of Public Utilities. (See Constellation Reaches Agreements to Keep Everett LNG Terminal Open.)

In response to feedback that the modeling approach “assumes higher LNG imports from Saint John than have been observed historically,” Zeng said the modeling approach is intended to calculate how much nonfirm gas is available when gas utility demand is accounted for, and modeling “unavailability due to economic reasons for the future is very difficult to predict and is generally not considered in the resource modeling.”

Regarding concerns about whether the modeling will adequately capture variability associated with extreme temperatures, Zeng said ISO-NE thinks the approach “reasonably reflects the gas fleet availability under different temperature conditions,” adding that the RTO “is open to further evaluating the inclusion of variability in the gas profile modeling as a future enhancement.”

Zeng also discussed how the RCA changes will affect how ISO-NE models the load profile in RAA. The load shape is currently built “by scaling the 2002 hourly load shape to reflect the forecasted seasonal ‘gross’ peaks.”

ISO-NE is planning to switch to “a composite seasonal load shape that is based on the 2021 annual net load characteristics and reflecting 2021 hourly weather for [April through September] and the 2013/14 hourly weather” for October through March.

Zeng noted that the 2002 load shape does not capture recent changes stemming from energy efficiency gains and behind-the-meter solar. He said the updates would better align ISO-NE with the methodology used in NPCC seasonal assessments.

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Eversource Finds OSW Buyer, Takes $1.95B Hit for 2023

Eversource Energy has finalized its long-running attempt to sell off its offshore wind assets, but not soon enough to avoid a $1.95 billion impairment for 2023. 

If the moving pieces come together as planned, the New England utility will be done with the struggling offshore wind sector, though it will continue to lead onshore transmission infrastructure work for the projects underway in its joint venture with Ørsted. 

Eversource announced the sale to Global Infrastructure Partners (GIP) after the financial markets closed Feb. 13, along with its fourth-quarter and full-year financials. Its stock, which has been trading near a five-year low, closed 4.7% higher in heavier-than-average trading Feb. 14. 

Eversource also said it will begin to evaluate market interest for Aquarion Water, the sale of which would bring an infusion of cash without resorting to the equity market. 

The sale of the offshore wind interests and the water utility would refocus the company on natural gas and electric transmission and distribution, which now provide the vast majority of its earnings. 

The Ørsted-Eversource venture has not been a failure: The partners expect to finish the nation’s first utility-scale offshore wind farm — South Fork Wind — next month, have begun construction of Revolution Wind and are far along in planning for Sunrise Wind. But the effort has been much more costly than expected, causing billions in losses for both.  

Ørsted, the world’s leading offshore developer, is pushing forward with some cutbacks. (See Ørsted Exits Offshore Wind Markets, Remains Committed to US.) But Eversource, New England’s largest electric utility, decided over a year ago to jettison what was becoming an albatross around its neck. 

Piece by piece, it has made progress. Ørsted bought Eversource’s share of their as-yet-undeveloped seabed leases, and it agreed to buy Eversource’s share of Sunrise if New York state awards Sunrise a new, more lucrative offtake contract to replace the one initially awarded to the partners. 

In the latest development, GIP will buy Eversource’s share of South Fork and Revolution. Eversource expects to realize approximately $1.1 billion in cash proceeds from the deal but said that could be higher or lower because of factors including construction costs, tax credit eligibility and project delays. 

An 8-K filing by Eversource on Feb. 13 indicates that GIP is guaranteed a pretax equity internal rate of return of 13% for Revolution and South Fork upon the start of commercial operations; if it is less, Eversource will pay GIP the difference, and if it is more, GIP will pay Eversource. 

The transaction cannot close without federal and state approvals. 

In a call with financial analysts the morning of Feb. 14, Eversource CEO Joe Nolan immediately launched into discussion of the proposed sale. 

“When we started down this path in 2016, we were very excited for the opportunity to bring much needed renewable energy to our region,” he said. “Unfortunately, our offshore wind investment experienced difficulties as early-stage projects.” 

These problems — inflation, interest rates, shortage of material and dearth of specialized vessels — came to the fore in late 2022, after several projects off the Northeast coast already had locked in offtake contracts at fixed rates, thus rendering the projects financially untenable. 

Developers in Massachusetts, Connecticut, New York, New Jersey and Maryland canceled projects or put them on hiatus; canceled offtake contracts; and dissolved partnerships. Ørsted took over Public Service Enterprise Group’s share of a now defunct New Jersey project, while Equinor and BP have agreed to divvy up their proposed wind farms off New York and New England. 

If all the pieces come together for Eversource, it will be a chance to exit offshore wind and refocus on gas and electricity with its feet firmly on land. 

“Our core business is well positioned to deliver solid operational and financial results as we move forward in supporting the region’s transition to a cleaner energy environment,” Nolan said. “Moving forward, Eversource will focus on the delivery of clean, safe, reliable energy to our customers.” 

In another 8-K filing Wednesday, Eversource reported a net loss of $442 million for 2023, which compares with net income of $1.4 billion in 2022. That breaks down to a 2023 loss of $1.26/share and 2022 earnings of $4.05/share. 

As Nolan indicated, the onshore businesses performed well: Electric, gas and water distribution, and electric transmission generated earnings of $4.34/share, compared with $4.09 in 2022. 

But impairments totaled a loss of $5.60/share for 2023, all but 2 cents of it attributable to offshore wind. 

The pretax impairment for 2023 was $2.17 billion: $400 million for Sunrise and South Fork in the second quarter, $545 million for Revolution in the fourth quarter and $1.22 billion for Sunrise in the fourth quarter. 

A $215 million tax benefit brought the after-tax impairment down to $1.95 billion for 2023. 

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Entergy States Debut Long-range Tx Cost Allocation Proposal, MISO Members Unconvinced

Entergy regulatory staff have revealed their vision for cost allocation on future long-range transmission projects, with multiple clean energy groups deeming the proposal incompatible with building a grid that’s ready for the future.  

The Entergy Regional State Committee (ERSC) Working Group debuted a preferred cost allocation for the upcoming long-range transmission plan (LRTP) portfolio of projects that will focus on MISO South. At a Feb. 9 teleconference, the ERSC said it prefers a 90% allocation based largely on adjusted production cost savings and avoided reliability projects, with the other 10% assigned to new generation in MISO South using a flow-based methodology. 

The draft allocation proposal doesn’t include a postage stamp to load components. The ERSC said it wants costs allocated as specifically as possible based on cost causation and beneficiaries’ pay principles. It also said other benefit metrics should be “accurate, objective, measurable, quantifiable, nonduplicative, forward-looking and replicable.”  

The ERSC also said LRTP projects that are proposed “solely to meet” state or local clean energy policies should be paid for in full by those jurisdictions.  

Last year, MISO proposed using a blend of a 50% postage-stamp allocation to load and a 50% allocation to the local transmission zone for MISO South LRTP projects. The new allocation is meant for the third LRTP portfolio and will be used in place of the 100% postage stamp to load allocation MISO is using for the first two LRTP portfolios aimed at the Midwest.  

The ERSC has said it won’t support any postage-stamp aspect in MISO’s LRTP allocation and therefore opposes the 50/50 allocation split. (See Entergy Regulators Mount Challenge to MISO South Cost Allocation.)  

MISO Members Doubt Projects Under Allocation

Members of MISO’s environmental and consumer advocates sectors seemed skeptical the allocation would foster any meaningful transmission expansion in the South. 

Sustainable FERC Project attorney Lauren Azar said MISO’s LRTP is “decidedly not” a local planning exercise and that regional projects deserve a regional allocation. She urged the ERSC Working Group to get advice from experts and involve state commissioners in allocation design decisions.  

Azar said the MISO community should “beware of a wolf in sheep’s clothing,” referring to cost-allocation designs “under which no projects would actually qualify for funding” because they are too prescriptive and convoluted.  

Yvonne Cappel-Vickery, the clean energy organizer for the Alliance for Affordable Energy, said she was especially concerned about the South’s provision that transmission furthering decarbonization be billed to states or cities with targets. 

Cappel-Vickery said the ERSC’s draft allocation is hostile to known clean energy benefits. She cautioned the ERSC against pushing an allocation style that considers “too few benefits.”  

“There is an ever-growing body of evidence pointing to the need for new transmission,” Cappel-Vickery said.  

Attendees pointed to the U.S. Department of Energy’s National Transmission Needs Study, which found the Delta region requires more transfer capability, and a working paper released by the National Bureau of Economic Research that concluded that Entergy Arkansas and Entergy Louisiana brought in about $930 million in profit in 2022 because of transmission constraints in their territories. 

Multiple attendees questioned how the ERSC envisions realistically handling the 10% allocation to new MISO South generation. 

Southern Renewable Energy Association’s Andy Kowalczyk asked whether MISO South’s proposal will create a bifurcated generator interconnection queue, where MISO South generation projects receive different treatment to work in extra transmission costs.  

Organization of MISO States Executive Director Marcus Hawkins asked if there was the potential for allocation “leakage” among the queue, where generation projects that aren’t located in the South benefit from the lines and are assigned costs for South LRTP lines. 

Hawkins also asked how MISO South envisions handling “blended” transmission projects that further both reliability and decarbonization goals.  

Sustainable FERC Project’s Natalie McIntire asked how it’s possible for the South to tease out when exactly an LRTP line is intended only for clean energy targets when, by design, LRTP lines are designed to deliver multiple benefits simultaneously. 

The ERSC Working Group didn’t provide justifications for their proposal during the teleconference. ERSC Working Group representative and Public Utility Commission of Texas economist Werner Roth explained the proposal and said he collected stakeholders’ questions during the teleconference and will take them back to the Entergy Regional State Committee board so they can “make an informed decision on how to proceed.”  

Southern Renewable Energy Association’s Simon Mahan said MISO South should be proffering a cost-allocation method that not only works for the third LRTP portfolio, but also the fourth LRTP portfolio, which will zero in on how MISO can expand the transfer capability between its Midwest and South regions. He said working out an allocation that could serve both would save MISO South time, energy and money.  

Mahan said he didn’t think the ERSC’s proposed cost allocation would result in the projects that would best position the South to serve future energy needs. 

“We’ve been experiencing constraints in MISO South currently and for quite some time,” Mahan said. He added his fear is that South region members advance a futile cost allocation that deters transmission projects.   

Kowalczyk said there have been longstanding issues with energy delivery in MISO South that need to be addressed with regional transmission projects. 

“Load pockets are not making this any better. There have been load pockets that have been persistent for decades,” he said, adding that MISO South needs to proactively become the grid of the future and not rely on interconnection customers to build out the grid in a “piecemeal” fashion.   

Kowalczyk also questioned if it was fair to place more cost burdens on interconnection customers, pointing out that for the 2021 class of MISO South generation projects, developers already face network upgrade costs of about $100 million per project. 

Entergy’s Matt Brown said there are “serious data errors” in DOE’s Transmission Needs Study that seriously undercount Entergy’s transmission work in the Delta region. Brown said combined Entergy transmission investment represented in its FERC Form 1 is six to 12 times higher than what was represented in DOE’s investment data. He said DOE used project data from MAPSearch, which missed about $700 million worth of Entergy projects in the Delta region.  

Brown also said there will be “enormous complexity” in addressing MISO’s Midwest-South transfer constraint.  

“It’s important to underscore that it’s not a simple issue,” Brown said, emphasizing that the constraint isn’t physical, but contractual and agreed upon more than 10 years ago by SPP, Southern Co., TVA and other parties.  

Brown said MISO and the joint parties to the contract could renegotiate the contract to be able to flow more power because the system is capable of greater flows than currently allowed. The agreement with seven joint parties — including SPP — limits transfers between MISO Midwest and South to 3,000 MW southbound and 2,500 MW northbound. 

Brown didn’t address MISO members’ other concerns with the cost allocation proposal.  

MISO said it has reviewed ERSC’s draft proposal and listened to stakeholders’ opinions during the Feb. 9 teleconference. Spokesperson Brandon Morris said MISO could weigh in on the allocation plan during a Feb. 26 meeting of the ERSC board of directors.  

MISO did not address RTO Insider’s other questions on whether it might consider eliminating the postage-stamp piece of its own allocation proposal, where its allocation proposal stands today or whether it believes it can cleanly isolate clean energy policy projects for allocation purposes.  

Suspicion from Watchdog Organization

Daniel Tait, research and communications manager at the renewables watchdog organization Energy and Policy Institute, agreed the ERSC’s proposal won’t result in regional projects that can pass muster. 

In an interview with RTO Insider, Tait said the ERSC’s allocation proposal seems counterintuitive because Entergy’s own service territory includes New Orleans, which has an ambitious 100% clean energy standard by 2035 and a goal for complete carbon neutrality by 2050.  

Tait said there are “clear financial incentives” to Entergy continuing to advance “local, emergency projects that are basically exempt from any type of scrutiny except for state approval.”   

“The results speak for themselves,” he said, noting the lack of regional South projects to prevail in MISO’s planning process.  

Tait said Entergy sometimes can pull in “hundreds of millions of dollars” more in a gas plant’s return on equity than when compared to a new transmission line’s ROE.   

“Whether they want to admit it or not, shareholders are forcing the C-suite to make these kinds of decisions every time. This isn’t pennies we’re talking about,” Tait said. “Somebody has to check that. I understand why they’re doing that, but where are the other parties that are supposed to rein this in?”  

Tait said he would argue the existing system in MISO South was broken before the ERSC introduced the proposal. The MISO South grid is “severely debilitated” today, Tait said, and unable to host meaningful new generation, as evidenced by expensive network upgrade costs for developers wishing to interconnect in MISO South.  

“So, by definition, nothing is ever going to get built unless Entergy goes to its regulators and says, ‘We need this,’” Tait said. 

Tait likened the slim interconnection opportunity and sky-high network upgrade costs in the South to a neighborhood Walmart at full capacity with a line out the door. When a new shopper is allowed in, they’re charged something like $100 per tomato, he said.  

“That’s a crazy assertion that we would never see in any other marketplace. Now, that messiness coupled with this plan ensures [Entergy] can continue to do whatever they want,” Tait said.  

Tait said while the future MISO South grid is uncertain, if Entergy is allowed to have its way, MISO South won’t reach its full potential for solar installment. He predicted that when solar capacity is built, it will be owned and controlled by Entergy “because it, and only it, will have the ability to navigate all these roadblocks that it’s thrown up.”  

Tait also said DOE’s Transmission Needs Study represents a snapshot in time and that it’s not incumbent on DOE to track down every utility’s recently approved transmission. He said DOE is correct that transmission planning in the Delta has been paltry, even accounting for the additional $700 million in projects that Entergy has planned from its “white castle” and has claimed the department omitted from the study.  

Tait said the main takeaway from DOE’s study is that the Delta region’s transmission planning has been badly neglected in the past decade. 

“Entergy and Southern Co. cannot deny that number is awful,” he said. “MISO South is going to get left behind, and what I mean by that most directly is that as an Entergy customer in MISO South, you’re losing access to a whole host of affordable clean energy. … That should be a big deal to customers right now.”  

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SPP, MISO Clash over Crypto-strained M2M Flowgate

SPP, MISO and its Independent Market Monitor are at odds over how congestion should be managed on a market-to-market flowgate taxed by a cryptocurrency mining operation within SPP’s borders.

The three filed comments with FERC this week over whether the 230-kV Charlie Creek-Watford line in North Dakota should remain under M2M coordination, when congestion stemming from the 200-MW Atlas Power Data Center is costing MISO members millions. (See Crypto Load on MISO-SPP M2M Constraint Draws Complaint from Montana-Dakota Utilities.)

Montana-Dakota Utilities filed a complaint on the ongoing controversy in late January, arguing SPP should be found in breach of the grid operators’ joint operating agreement for unjustly taking M2M payments from MISO to manage local congestion. MISO and its IMM agreed the line’s M2M status should be lifted; SPP argued for the status quo (EL 24-61).

SPP contends there is no basis for Montana-Dakota Utilities’ complaint because the more than 3-year-old M2M flowgate is “clearly authorized” by the MISO-SPP joint operating agreement and other arrangements between it and MISO. It said an order for refunds would be illegal in this case, and it asked the commission to deny the complaint.

“Moreover, SPP and MISO are already discussing prospective enhancements to the removal provisions under the JOA’s dispute resolution process. SPP hopes that these discussions will successfully address the future operation of Flowgate 5717, while also avoiding near-term reliability risks and ensuring that similarly situated M2M-coordinated flowgates are treated comparably,” SPP said.

SPP said there’s no need for FERC to initiate hearing and settlement procedures or an alternative dispute resolution and that doing so could be “needlessly disruptive.”

SPP pushed back against Montana-Dakota’s claim that the flowgate is a local constraint, not a regional one. It said the constraint passed multiple eligibility studies before it was designated for M2M coordination.

“To the best of SPP’s knowledge, MISO has never objected to the results of the flowgate studies,” SPP said. The RTO also said it continues to believe M2M coordination on the flowgate is an “effective mechanism to manage congestion.”

SPP also said nothing in MISO and SPP’s agreements prohibits constraints from becoming M2M-coordinated flowgates just because they’re situated in a load pocket.

However, MISO Independent Market Monitor David Patton said the nature of the load addition means Charlie Creek shouldn’t be designated as an M2M flowgate.

Patton said while Charlie Creek technically passed the tests laid out in MISO and SPP’s congestion management process, the flowgate’s congestion now is local and is “not a regional issue that M2M coordination was intended to address.” He added that MISO, SPP and PJM in the past have agreed to remove flowgates from M2M procedures on a case-by-case basis when impacts are found to be local.

“[I]t is understood that this congestion is almost entirely managed by generation inside the [Williston load pocket (WLP)], almost none of which is operated by MISO. Likewise, MISO has no meaningful resources that can be used outside the WLP to provide relief on the Charlie Creek flowgate. These characteristics clearly indicate that the congestion on the Charlie Creek flowgate is local in nature and, as such, was never intended to be the type of flowgate that should be coordinated,” the Monitor argued.

MISO itself said negotiations with SPP over the flowgate effectively are at a stalemate. It said it is seeking immediate removal of Charlie Creek from joint congestion management and for SPP to return all associated M2M payments it made to SPP starting April 1, 2023. MISO said the “only practical result of the M2M coordination on that flowgate is an unjustified financial subsidy to SPP from MISO customers.”

MISO told FERC it objects to “SPP’s improper application of the M2M coordination protocol” on the Charlie Creek line. But it said it remains unable to remove Charlie Creek from M2M coordination, even after engaging in negotiations with SPP pursuant to their formal dispute resolution rules.

The MISO-SPP JOA allows the RTOs to cease M2M congestion management on flowgates when the process isn’t effective at curbing congestion. However, both MISO and SPP must consent to striking the flowgate from congestion coordination before it can be terminated.

MISO said it has repeatedly requested that SPP agree to eliminate the M2M designation on the line, but SPP “steadfastly refused, turning the consent requirement into a veto.”

MISO asked FERC to take swift action to “stop the unjustified flow of M2M payments” and direct it and SPP to draft revisions to their M2M coordination procedures to avoid similar situations in the future. It asked that FERC fast track Montana-Dakota Utilities’ complaint, given that its M2M payments to SPP are likely to rise when lower, summer ratings are applied to the line beginning in April.

MISO said it was well known that the Williston load pocket had longstanding congestion issues and said the recent load addition means its resources can offer near-zero relief.

“When SPP added a significant new load, the Atlas Power Data Center, to the WLP in early 2023, it exacerbated the existing constraints while neither SPP nor MISO have sufficient generation in the area to relieve those constraints. In other words, there is no economic M2M coordination solution that the RTOs may provide through redispatch to alleviate congestion,” MISO explained.

MISO argued that SPP acknowledged the load pocket’s issues in its 2021 Integrated Transmission Planning Report prior to the cryptocurrency mining facility’s operation. In the 2021 report, SPP said “the root of the issues in the [Williston load pocket] is the lack of transmission to accommodate the level of transfers required to serve the forecasted load in the future, contributing to a weak system unable to maintain acceptable voltage levels.”

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Consumer Collective Again Asks FERC to Strike ROFR Laws from MISO Planning

An alliance of consumer groups has asked FERC to address its 2022 joint complaint against MISO’s practice of deferring to state right of first refusal (ROFR) laws in its regional transmission planning.

The alliance — which includes the Industrial Energy Consumers of America, the Coalition of MISO Transmission Customers and others — said “despite the significant rate impact on consumers, the commission has not ruled on the complaint” (EL22-78).

In the summer of 2022, the consumer alliance asked FERC to block MISO and other RTOs from applying “anticompetitive” state ROFR laws to their regional transmission planning and cost allocation processes. The group said MISO shouldn’t hamstring itself by maintaining tariff provisions that prohibit it from holding a competitive solicitation for regionally cost allocated projects. It also argued that state-level ROFRs interfere with FERC’s “exclusive jurisdiction to set just and reasonable rates for transmission in interstate commerce.” (See Consumer Groups File FERC Complaint Against MISO.)

Now the alliance has said FERC’s inaction has allowed uncertainty to fester, as evidenced by MISO asking an Iowa court to lift an injunction against some of its long-range transmission plan (LRTP) after Iowa’s ROFR was deemed unconstitutional. (See MISO Asks Court for Injunction Reversal on Iowa LRTP Projects.) The group said MISO’s argument that FERC alone has the power to oversee any change in developers coincides with its complaint that FERC should be able to override state-level ROFRs in transmission planning.

The consumer alliance said the litigation and delay among the Iowa LRTP projects are a “concrete example” that it’s unreasonable for MISO to continue to yield to state ROFRs.

“The ROFR law exception in MISO’s tariff — as played out in the state of Iowa — has hampered MISO’s ability to select the more efficient or cost-effective developer in a timely manner or to effectively facilitate transmission development subject to the commission’s exclusive jurisdiction. And now MISO asserts that its determination to skip competition cannot be undone by a state court ruling that the law was unconstitutional from the inception,” the alliance argued.

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Duke Energy Projects Higher Earnings, Load Growth in 2024

Duke Energy has upped its forecast for growth across its territories, driven by migration, economic development and government funds, the company said during a Feb. 8 call to report its year-end earnings.

The company is entering the year with “significant momentum,” CEO Lynn Good said. For the first time in decades, Duke is beginning the year as a fully regulated utility following the July sale of its last renewables business. (See Duke Energy Sells Distributed Renewable Business to ArcLight.)

With this regulatory “transformation,” Good said, the company is “poised to deliver on [its] simplified, 100% regulated growth plan.”

Duke Energy’s Service Territory | Duke Energy

Duke’s long-term load growth projections increased to 1.5-2%, CFO Brian Savoy said. This growth is underpinned by economic development projects coming online, strong residential growth and a post-COVID trend of customers returning to their offices. “Those three factors give us confidence that 2% load growth in ’24 is definitely in our sights,” Savoy said.

Duke Energy’s third-quarter earnings call projected load growth of 0.5-1%. (See Duke Earnings Slip on Low Demand, but Long-term Growth Expected.)

To keep up, Good said a “record infrastructure build” is ongoing across Duke’s fastest-growing jurisdictions.

In Florida, where the number of customers grew 2% from 2022 to 2023, 300 MW of solar additions are under construction, with expectations of 1.5 GW of in-service solar in the state by 2025.

In the Carolinas, which grew by 2.1%, annual solar procurement targets of over 1 GW are in place. Duke plans to file Certificates of Public Convenience and Necessity for 2 GW of natural gas generation in North Carolina this year as well. Growth in the Carolinas is outpacing the forecast from August’s resource plan, Good said, leading the utility to file supplemental plans in January.

Duke added 195,000 customers in 2023 across all jurisdictions, Savoy said.

Nuclear PTCs

2024 marks the first year Duke can claim the nuclear production tax credits (PTCs) implemented under the Inflation Reduction Act. Savoy said the utility expects to claim several hundred million dollars of the credits.

These benefits will be amortized over four years, reducing customers’ electric bills during that time, Savoy added.

Financials

Adjusted earnings per share were $5.56, compared with $5.27 at the end of 2022, a growth rate of about 6%. This growth came primarily from rate case outcomes, multiyear rate plans and rider growth across the utility’s territory.

The utility projected yearly growth of another 6-7%, to a range of $5.85-$6.10. This is expected to be driven primarily by electric utilities and infrastructure, particularly North Carolina’s “historic” base case, Savoy said. Updated rates in Kentucky and expected updated rates in South Carolina also will drive this growth, he added.

This growth will be offset by the utility’s average tax rate, which sits at 10% but is expected to increase to 12-14%, as well as “depreciation and property taxes on a growing asset base,” Savoy said.