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December 13, 2025

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SPP Addresses 3rd Load Shed Since March 31

OMAHA, Neb. — SPP staff have told its state regulators and board members that it will do better after three local load sheds since March 31.

The outages affected a combined 54,000 customers in northwestern Louisiana and mostly oil and gas facilities in southeastern New Mexico.

“They’re concerning, and we are committed to analyzing what went wrong and what we need to do to get better,” SPP CEO Lanny Nickell said May 5 during the Regional State Committee’s quarterly meeting.

The most recent, and largest, load shed since Nickell became CEO came April 26 near Shreveport, La., in Southwestern Electric Power Co.’s (SWEPCO) service territory. SPP said it identified grid instability in the area and directed SWEPCO to immediately reduce its electricity use by 140 MW, resulting in a six-hour outage for about 30,000 residential customers in Caddo and Bossier Parish.

Bruce Rew, SPP’s senior vice president of operations, told the RSC and stakeholders that temperatures came in higher than forecasted, increasing load. With several generators and transmission lines out for planned maintenance, the grid operator didn’t have enough generation to respond to voltage instability in the area.

Coming as it did three weeks after a similar event, the outage generated numerous headlines in the region:

Foster Campbell, the outspoken Louisiana commissioner who serves northern Louisiana and once ripped SPP for its “Taj Mahal” of a headquarters building, held a press conference in his office April 29. (See Louisiana’s Campbell Expands Beef with SPP.)

Campbell called Nickell and SWEPCO President Brett Mattison and sat them alongside him, where they held court before the regional media for about an hour. One image from the press conference showed Nickell, his head bowed, listening to Campbell as the commissioner looked at the CEO and pointed to a document.

Nickell noted to the RSC that the event occurred during a pleasant spring afternoon.

“What I found is there’s never a good time to take an outage. There’s never a good time to interrupt service,” he said. “It’s important that we never take for granted what we do to keep the lights on.”

Campbell has asked SPP and SWEPCO staff to attend the Public Service Commission’s next meeting and discuss compensation for the outage’s damage. SPP has said it will have representatives at the meeting.

“Let’s see about how we can get together and how much money would be reasonable or fair,” Campbell said during the press conference. “We’re going to work this out and come up with a solution. We gotta figure out how you give these people their money back that lost its revenues while the power was down.”

The RTO has said it will work with SWEPCO to conduct a comprehensive analysis of the event to understand what happened and determine future actions.

“We will consider all possible solutions to issues that threaten real-time and long-term reliability across the region we serve,” SPP said in a statement.

The Shreveport area also went through an emergency outage April 2 after a dangerous storm system swept across the Midwest. More than 24,000 customers were without power for several hours. SWEPCO said it was required by SPP to implement “emergency grid protection outages” to prevent “potentially catastrophic damage” to the grid.

A SWEPCO representative told one of the regional media outlets that emergency outages like the April 2 event are “incredibly rare” and not something that happens regularly.

The third load shed took place March 31 in Southwestern Public Service Co.’s (SPS) eastern New Mexico service territory, which has dealt with slim generation margins recently, Rew said. Several generators were out of service for planned maintenance or forced outages, and when there was a steep drop in wind production during the early morning, the reliability coordinator ordered SPS to drop 122 MW of load.

The outage affected primarily large industrial consumers and lasted less than three hours before offline generation could be deployed.

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FERC Approves $110K Penalties in RF

Two entities managed by Cogentrix Energy will have to pay a collective $110,000 to ReliabilityFirst for violating NERC’s reliability standards, according to a settlement between the regional entity and the utilities approved by FERC (NP25-9). 

NERC filed the settlement with the commission in a notice of penalty March 31, along with a separate spreadsheet notice of penalty containing a settlement between SERC Reliability and Georgia Transmission (GTC), and another settlement between SERC and the Municipal Electric Authority of Georgia (MEAG), both for failing to maintain consistent facility ratings (NP25-10).  

FERC said in a filing April 30 that it would not further review any of the settlements, meaning the penalties for the RF violations will remain intact. Neither of the SERC settlements carried a monetary penalty. 

Communication Issues Between Cogentrix, PJM

RF’s filing involved two gas generating facilities: the 870-MW Hamilton Liberty station in Towanda, Pa., and the 773-MW Essential Power Rock Springs (EPRS) station in Rising Sun, Md. Liberty is registered with NERC as a generator owner and generator operator, while EPRS is registered as a GO, GOP and transmission owner. 

Liberty and EPRS were accused of infringing IRO-001-4 (Reliability coordination — responsibilities) and TOP-001-5 (Transmission operations), respectively. RF said both violations stemmed from “the same manager’s miscommunication [when] both entities were experiencing a phone outage,” and both were self-reported to the RE on Nov. 15, 2021.  

According to the NOP, on Sept. 16, 2021, Liberty was preparing to perform reactive testing for a 453.5-MW unit as required by MOD-025-2 (Verification and data reporting of generator real and reactive power capability and synchronous condenser reactive power capability). The test was approved by Liberty’s reliability coordinator, PJM, except for one portion.  

In its self-report, Liberty explained that Cogentrix’s Energy Management Group (EMG) “was experiencing a [voice-over-IP] phone outage that created additional confusion in the EMG to PJM communications” at the time, requiring the use of multiple cell phones that “were not utilized by PJM as intended by EMG.”  

PJM told the manager of the EMG that because of an ongoing transmission outage, the leading reactive test could not be performed at the maximum MW output. The RTO told the manager that “a lengthier stability study was required prior to performing that portion of the test.”  

However, the EMG told Liberty’s control room operator to start the test without passing along the information about PJM’s lack of approval for one portion. As a result, the operator conducted the test in full. This constituted a violation of IRO-001-4 requirement R2, which requires transmission operators, balancing authorities, distribution providers and GOPs to “comply with [their RCs’] operating instructions unless compliance … cannot be physically implemented or …such actions would violate safety, equipment, regulatory or statutory requirements.” 

Also on Sept. 16, 2021, PJM requested through the EMG that EPRS run Units 3 and 4 for economics. The EMG manager relayed this instruction to the EPRS lead operator, but the operator did not hear the request clearly. Although the operator repeated it back as an instruction to use Unit 4 only, the manager did not correct this misunderstanding.  

As a result, the EPRS operator did not start Unit 3 until called back by the EMG’s real-time desk operator to ask why the unit was not running. At this point, the EPRS operator listened to the recordings and realized he had missed the request for Unit 3 to be started. EPRS contacted PJM to notify the RTO that it had failed to bring Unit 3 online, and PJM canceled the request. 

The failure to convey PJM’s directive violated requirement R5 of TOP-001-5, which, like IRO-001-4, requires TOPs, GOPs and DPs to “comply with each operating instruction issued by” their BAs. RF assessed the TOP-001-5 infringement as a minimal risk to grid reliability. However, the RE assessed the other issue as a serious risk because performing the reactive test without a stability study could have caused the unit to trip, damaging station equipment and further jeopardizing grid reliability. 

To mitigate the miscommunications that led to the lapses, both Liberty and EPRS conducted an extent of condition review of their communications with Cogentrix’s EMG from October 2021 to January 2022 and found no further instances of failure to follow operating instructions. They also developed plans to manage communication with PJM and other plants during future phone outages by the EMG. 

RF assigned a penalty of $85,000 for the IRO-001-4 infringement, and $25,000 for the TOP-001-5 violation. 

Georgia Entities Settle Over Ratings Issues

SERC’s settlement with GTC started with a self-report filed Oct. 12, 2022. The utility indicated it was in violation of FAC-008-5 (Facility ratings). 

While reviewing drawings and equipment logs for its Bolingbroke substation, GTC found that a line elements database maintained by another registered entity did not list the correct jumpers or bus, likely the result of improper record keeping during a conversion from 68 kV to 115 kV in 1999. The utility derated the relevant line, restoring the previous rating several months later when the bus and jumpers were replaced. 

GTC then conducted a walkdown of 699 additional stations, finding 10 incorrect facility ratings that resulted in derates of up to 32%. SERC later conducted an audit in 2023 that found no additional instances of noncompliance. 

The RE assessed the root cause of the infringement as ineffective controls, primarily because of outdated procedures for communicating facility ratings that were not updated to incorporate new technologies. GTC’s mitigation activities — which are expected to be completed Dec. 31, 2025 — include updating its project review checklist to require verifying the actual transmission line ratings, completing an extent of condition review and committing to correct its internal records as necessary. 

SERC discovered MEAG’s violations — also of FAC-008-5 — through a compliance audit. The RE conducted a walkdown of MEAG’s facilities and found that some of the installed equipment was not included in the ratings table provided by the entity for one of its substations. Among the omissions were all the jumpers, along with a conductor and the name plate size of a switch at the facility. 

After the audit, SERC required MEAG to conduct a walkdown assessment of eight additional transmission stations. The utility identified one incorrectly rated element that led to a 10% derate on a 115-kV line. 

In this case, SERC attributed the misratings to a failure to follow internal controls, which meant that all applicable elements were not included in the facility rating database. MEAG committed to update its ratings database and participate in training on proper facility rating change management procedure. The utility also promised to perform walkdowns of all elements applicable to FAC-008, starting in the third quarter of 2024 and with an expected completion date of Dec. 31, 2025. 

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NEPOOL Supports Timeline Revisions for ISO-NE Order 2023 Compliance

The NEPOOL Participants Committee on May 1 voted to support an expedited filing adjusting several key dates in ISO-NE’s compliance proposal for FERC Order 2023.

The commission approved ISO-NE’s compliance filing on April 4, but several dates included in the filing no longer are viable (ER24-2009, ER24-2007). (See FERC Approves ISO-NE Order 2023 Interconnection Proposal.)

To preserve the general timeline of its proposal, ISO-NE intends to push back most dates and deadlines in its original filing by about a year. This would enable the RTO to run a group study for late-stage interconnection requests that lack capacity interconnection rights. The group study would precede the main transitional cluster study, which is likely to begin in October.

A proposed revision by RENEW Northeast failed to gain enough support to pass despite support from the NEPOOL Transmission Committee. RENEW proposed to let customers with late-stage interconnection studies continue their system impact studies (SISs) until Aug. 30, arguing this could help these developers avoid restarting their studies. ISO-NE stopped working on all in-progress SISs after FERC approved its compliance proposal. (See ISO-NE Prepares Expedited Filing After Ruling on Order 2023 Compliance.)

Prior to the meeting, NEPOOL Counsel Pat Gerity told members that the Participating Transmission Owners Administrative Committee did not support filing the changes with RENEW’s revision. He wrote that, “because of the shared filing rights that are implicated, the ISO does not believe it will be in a position to file the TC-recommended Section II revisions.”

The revision fell short of the two-thirds threshold required for PC support, with 59% of the committee voting in favor at the meeting on May 1.

The PC also voted to support changes to a pair of definitions in the ISO-NE Financial Assurance Policy and approved minor changes to the operating procedures for transmission outage scheduling and metering and telemetering criteria.

Operations Report

Energy market revenues significantly increased in April compared to the same month last year, ISO-NE COO Vamsi Chadalavada told the PC.

Average day-ahead and real-time hub LMPs increased by more than 65% year-over-year. The revenue increase largely was driven by more-than-doubled natural gas costs.

ISO-NE’s day-ahead ancillary services (DAAS) market, which the RTO launched at the beginning of March, had an average daily total value of about $15 million. Following a significant price spike after the market launch in early March, DAAS prices have remained relatively stable, but they did experience a smaller spike during a period of cold weather and elevated demand in early April.

The system did not experience any emergency conditions but did experience the lowest minimum load in ISO-NE history. (See Growth of BTM Solar Drives Record-low Demand in ISO-NE.)

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Around the Corner: Nobody Does Capacity Quite Like Ontario

Twenty-two years after it went live, Ontario’s independent electric system operator, IESO, has launched its Market Renewal Program (MRP), instituting a nodal day-ahead market that covers more than 900 locations. 

The revision appears to have gone smoothly, with the grid operator now joining the seven U.S. ISOs and RTOs that have day-ahead structures. Given that fact, it’s an opportune time to look at the bigger picture of Ontario’s structure and competitive electricity markets in general. 

DA markets typically are where the largest volumes of electricity are transacted on a location-specific nodal basis, with varying levels of nodal granularity. Under its earlier approach, IESO had operated only a real-time market with a single price, irrespective of location or transmission constraints. 

Generators could schedule their output the day prior, but commitments were not financially binding. Any inefficiencies or price discrepancies, including congestion, were settled through compensatory out-of-market payments, and discrepancies between expected generation and actual real time operations were not subject to penalty.  

Under the new MRP, day-ahead market offers — which create financial obligations to deliver energy the following day — will be scheduled to match forecast demands. Prices will be bound by a floor of -$100/MWh and a ceiling of $2,000/MWh.  

In some ways, it’s surprising the move took so long. Locational day-ahead markets create more market efficiency while also offering grid operators and market participants better foresight into what will happen the following day. They are more deliberately proactive and less reactive to real-time events.  

The move was a big step for IESO and one of the biggest tweaks to its market design in years. And while it increases the overlap in the Venn diagram with other market operators, IESO’s action and market redesign highlights a very curious fact about North America’s restructured markets: Each “deregulated” market embraces the overriding concept of competition but then spikes the drink with its own highly local flavors. 

ontario

Peter Kelly-Detwiler

Editorial pet peeve: It’s not clear why people insist on calling this “deregulation.” With highly complex competitive markets superimposed on regulatory supervision for distribution at the state or provincial level, there are far more — and more complex — rules than ever existed before the advent of competition. And operators keep tweaking them to respond to the latest perceived market shortcoming. 

These market flavors also defy any attempt by generators, battery operators or demand response aggregators to achieve economies of scale — no, we have created a true Tower of Babel here.  

To illustrate the nature of this multifaceted hydra, let’s take the issue of capacity in a number of markets. Texas has no capacity market, letting energy scarcity prices offer the signals, although operating reserves are in the mix as well. Meanwhile, ISO-NE and PJM hold formal capacity market (FCM) auctions three years in advance — unless the regulatory conversation gets so muddled that they get delayed for years, as has been the case for PJM. 

New York long ago decided the FCM approach was too potentially inefficient and risky, and opted for monthly options with the possibility of transacting seasonal strips. Meanwhile, on the West Coast, California’s ISO tasks the utilities with procuring capacity resources. 

In many markets, capacity represents a noticeable element on the wholesale power bill. Exhibit A is PJM, with its recent eye-watering 2025/26 auction results at just under $270/MW-day, and the just-formalized floor and ceiling prices of $175 to $325/MW-day for the coming two auctions. Exhibit B is MISO’s just released auction results for this summer, coming in devilishly high at just over $666/MW-day and annually between $212 and $217/MW-day. They make PJM look tame by comparison.  

But nobody does capacity quite like Ontario, and that hasn’t changed with its Market Renewal.  

Capacity and the Global Adjustment Charge (GAC)

As in other markets with capacity prices, the GAC — established in 2006 — is intended to cover the cost of building and maintaining supply infrastructure to ensure system resource adequacy. The initial MRP proposal intended to do away with the GAC and replace it with a formal capacity auction. However, pushback from various stakeholders resulted in this plan being abandoned.  

Unlike the role of capacity pricing in other markets, though, the GAC specifically addresses the difference between the total compensation made to certain contracted generators and any offsetting market revenues. As such, there typically has been a strong inverse relationship between wholesale electric energy prices and the GAC. When wholesale energy prices are lower, the GAC is higher, and vice versa. And energy prices historically have been very low, with the result that the GAC typically is the largest single element on the average consumer’s total wholesale power bill, often representing up to 65% or more of the monthly costs.  

Ontario’s GAC will continue under the new program, but its impact and interaction will change slightly. The greatest impact may simply be that it will reflect greater location-specific volatility resulting from a nodal pricing program that specifically integrates the impact of congestion. 

Lower hourly energy prices will result in higher compensatory GACs, and higher prices will result in the opposite. Only time will tell whether capacity costs will decline as a total percentage of the entire wholesale bill. But if the history of many other grid operators is any guide, the rules-tweaking is far from over. Call it whatever you want, but don’t call it “deregulated.” 

Around the Corner columnist Peter Kelly-Detwiler of NorthBridge Energy Partners is an industry expert in the complex interaction between power markets and evolving technologies on both sides of the meter. 

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MISO Petitions 8th Circuit in Dispute with SPP over Data Center-strained Flowgate

MISO is seeking judicial review of two related FERC decisions preventing the RTO from recouping costs or revising a joint procedure with SPP over a shared North Dakota transmission line that has become congested by a new cryptocurrency mining facility.   

The RTO on May 1 filed a petition for review with the 8th U.S. Circuit Court of Appeals over the commission’s previous orders declining a request that SPP refund MISO members or change procedures around the overworked 230-kV Charlie Creek flowgate (ER24-1586, et al).  

The flowgate ran up tens of millions of dollars in congestion costs after the Atlas Power Data Center in Williston, N.D., activated on the SPP side of the line in 2023. MISO and its member Montana-Dakota Utilities maintain that associated market-to-market (M2M) settlements unfairly involved MISO in SPP’s localized issue brought on by 200 MW of poorly planned data center growth.  

FERC in March denied requests by both MISO and Montana-Dakota Utilities for rehearing to obtain refunds from SPP or cancel eligibility for the flowgate’s ongoing M2M coordination. The commission said the Charlie Creek Flowgate passed the RTOs’ flowgate eligibility studies for such coordination. (See FERC Again Declines Changes, Refunds on Crypto-burdened MISO-SPP Flowgate.)  

According to the agreement between the RTOs, MISO must secure SPP’s permission to remove M2M coordination from the flowgate. 

MISO also unsuccessfully sought for FERC to alter the MISO-SPP interregional coordination process — which manages flowgates — to make it easier for one RTO to revoke M2M status on a line if it doesn’t think the designation can assist with relieving a constraint. FERC decided that while a section of the two RTOs’ interregional coordination process says M2M coordination should be reserved for issues that are regional — rather than local — that requirement is not an explicit prerequisite for a flowgate to hold an M2M designation.  

MISO has claimed that unwarranted M2M coordination has cost its members $38 million in charges to manage congestion on the flowgate, even as its members can offer only less than 1 MW of relief. However, FERC said SPP’s evidence shows that revoking Charlie Creek’s M2M flowgate status might risk the RTO needing to resort to transmission loading relief or load shedding.  

MISO did not return RTO Insider’s request for comment on how much the RTO estimates its members are owed in refunds or whether it believes growing data center load would produce more flowgate issues at its seam with SPP.

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CRES Urges Federal Support for Cleaner Hydrogen

A conservative-leaning energy advocacy group is out with a new report on the value of methane-based hydrogen production paired with carbon capture and storage.

So-called “blue” hydrogen is poised to help expand U.S. energy dominance as the global market for lower-emissions hydrogen takes shape, the authors write, and federal incentives are essential for the nation to remain competitive in the early stages.

The Citizens for Responsible Energy Solutions (CRES) Forum report released May 5 included modeling analysis that projected tens of thousands of new jobs and tens of billions of dollars in economic impact from a robust blue hydrogen sector.

The report comes amid ongoing debate over clean-energy tax credits created under former President Joe Biden, which subsequently were targeted by President Donald Trump but are finding support from some Republican lawmakers who see economic benefits in their districts from those credits.

Among these are the 45V clean hydrogen production tax credit. It and other incentives are “essential” for helping the United States stay competitive in the emerging market, the authors write, as the advanced technology involved carries high upfront costs.

While U.S. industrial decarbonization initiatives no longer enjoy the same level of support as they did under President Biden, the report notes that other major economies continue to ramp up such efforts.

“The U.S. benefits from abundant natural gas resources and technological leadership in CCS, making it uniquely positioned to become a global leader in blue hydrogen production,” the authors write.

Their analysis of data from the International Energy Agency shows that all blue hydrogen projects publicly proposed in the United States would have a combined annual production capacity of 9.8 million metric tons by 2035.

Using multiple scenarios, the report calculates:

    • Construction of those plants nationwide could support 29,000 to 79,000 construction jobs through 2035.
    • Texas and Louisiana would see the largest boost in construction employment.
    • Construction could have an annual economic impact of $6.7 billion to $18.7 billion.
    • Annual operations would support 18,000 direct jobs and 44,000 indirect or induced jobs.
    • The bulk of those permanent jobs again would be in Texas and Louisiana.
    • Operations would support $22.4 billion in economic output.

Production of 9.8 MMT of blue hydrogen also would ripple through the natural gas industry, creating steady demand and supporting nearly 6,800 direct jobs, the report estimates.

The authors note that roughly two thirds of announced blue hydrogen production would be devoted to ammonia, most of it for fertilizer. The remainder might be used mainly for petroleum refining and transportation, with a small amount going to steel production.

“The 45V tax credit is not just an investment in energy; it is an investment in America’s economic strength, industrial leadership and long-term global competitiveness,” the authors write.

Dramatically increasing the production and dramatically decreasing the production cost of clean hydrogen was one of Biden’s high-profile Earthshot initiatives, but the vision was hampered by the slow rollout of details crucial to investment decisions. The 45V tax credit rules were not finalized until two weeks before Trump’s inauguration.

Beyond the economics, there is disagreement over how “clean” various types of hydrogen generation really are, and there was spirited argument between industry lobbyists and environmental advocates over the details of 45V as they were being finalized.

Those details play a critical part in how expensive production is and how impactful it is on the environment.

Hydrogen itself does not create carbon dioxide when burned or run through a fuel cell, but significant amounts of the greenhouse gas can be generated through hydrogen production.

Also, given that hydrogen produces less energy per unit of volume than methane, more hydrogen may be needed for a given application.

Finally, the carbon capture and storage that is integral to blue hydrogen also consumes energy.

There is room for reduction, however — the vast majority of U.S. hydrogen production is “gray,” which essentially is the same as blue hydrogen but without carbon capture.

Environmental advocates press instead for “green” hydrogen — emissions-free hydrogen produced with emissions-free electricity newly built for that purpose. Green at present is much more expensive than gray.

CRES is a nonprofit seeking to educate Republican lawmakers and the public about conservative solutions to address U.S. energy, economic and environmental security while increasing the nation’s competitive edge. It identifies its goal as lowering global emissions to maintain a clean environment and mitigate the impacts of climate change.

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CalCCA Study Touts Benefits of RA Trading at Hourly Level

The cost of electricity in California could be reduced if energy providers were allowed to trade their resource adequacy products by the hour, a new study by the California Community Choice Association (CalCCA) says. 

Currently, load-serving entities submit annual and monthly RA reports to the California Public Utilities Commission. In the reports, each LSE must demonstrate it has procured 90% of its system RA obligation for the five summer months of the coming compliance year and that it meets 90% of its flexible RA obligation for all 12 months. Under existing regulations, California LSEs are limited to trading RA products that cover an entire month. 

In 2024, CPUC started the first “Slice of Day” (SOD) RA program in the U.S. The program requires each LSE to demonstrate sufficient capacity in all 24 hours on CAISO’s “worst day” in a month, i.e., the day of the month that has the highest forecast peak load. 

However, in the SOD program’s first year, many LSEs had more resources than needed, while other LSEs did not have enough, CalCCA’s paper says. This outcome “suggests there are additional opportunities for trade that are currently unrealized due to regulatory barriers,” it says. It therefore argues for an hourly obligation trading model in order to reduce costs to consumers.  

“This is about fairness and common sense,” CalCCA CEO Beth Vaughan said in a press release. “Let’s stop making energy providers buy more capacity than they need, and let’s stop making Californians foot the bill.” 

CalCAA estimated that average RA prices could decrease by $1/kW-month for every 1-GW demand reduction in the new hourly model. The reduced demand for RA products on the market lowers the price of RA and the cost of meeting RA obligations for all California LSEs. 

Reducing the cost of RA in California has grown in importance in recent years following the rapid increase in RA prices, the paper says. For example, the weighted-average RA price was $2.77/kW-month in 2019 but increased by a factor of nine to $26.26/kW-month in 2024, according to the paper. 

Policymakers should support the development of effective trading mechanisms that go hand in hand with the transition to SOD, CalCCA’s paper says. Otherwise, the SOD program will drive up costs for consumers with no direct benefit to reliability. 

But CalCCA noted that its study is based on simulations and that a “real-world” implementation would require a much more in-depth investigation. 

“Implementing an effective trading mechanism with the SOD program will not be easy,” the paper says. “Trading in the SOD policy environment is six to nine times more complex than that of the legacy monthly RA product and will require a greater volume of trades, more transactions and more trading partners.” 

A key principle of CPUC’s current RA program is balancing addressing hourly energy sufficiency with advancing California’s clean energy, greenhouse gas emissions-reduction and air pollution-reduction goals, spokesperson Terrie Prosper told RTO Insider. With increasing penetration of renewable resources, CPUC sought to construct the SOD framework to better manage reliance on use-limited resources in meeting reliability needs, Prosper said. 

Trading RA obligations at the hourly level would not influence natural gas generation in California, Prosper said. The RA framework — both the previous structure and the SOD — is a planning construct and does not directly determine how much gas generation will be dispatched in the energy markets. 

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FERC Accepts ISO-NE Compliance Filing on Interconnection O&M Costs

FERC on May 2 accepted a compliance filing by ISO-NE and New England transmission owners eliminating interconnection customers’ responsibility to pay for the operations and maintenance costs of network upgrades (ER25-1324).  

The commission ordered an additional filing to address potential issues regarding refunds for O&M costs incurred after its initial ruling in December 2024. (See FERC Sides with New England Developers on Interconnection Complaint.) 

“The compliance filing largely complies with the [commission’s] directive to remove from the tariff any language providing for the assignment of O&M costs for network upgrades to interconnection customers,” FERC wrote. 

The commission also accepted tariff changes broadening the definition of an “interested party” in the New England TOs’ formula rate protocols, which should enable a wider range of groups to participate in proceedings. 

NEPOOL, RENEW Northeast, Advanced Energy United and the Alliance for Climate Transition supported the filing, while the New England Power Generators Association and CPV Towantic expressed concern it inadvertently would limit refunds to payments made after the December order, leaving out advance payments for costs incurred after. 

FERC directed ISO-NE and the TOs to make an additional filing within 30 days “to clarify that network upgrade O&M costs accrued on or after Dec. 19, 2024, will be returned to the interconnection customer, regardless of whether the interconnection customer made advance payments prior to” that date. 

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Coastal Virginia Offshore Wind Sees Costs Increase from Trump Tariffs

Dominion Energy’s Coastal Virginia Offshore Wind (CVOW) project has weathered most of the issues facing offshore wind, but the company said during its first-quarter earnings call May 1 that the project faces risks from President Donald Trump’s tariffs.

The project is 55% complete and months away from the first delivery of energy to customers in 2026, and is on track for 100% completion that year, Dominion CEO Robert Blue said.

“It represents the fastest and most economical way to deliver almost 3 GW of electricity to Virginia’s grid to support America’s AI and cyber preeminence and the largest data center market in the world; to support U.S. shipbuilding at customers like Huntington Ingalls — the largest military ship building company in the United States and one of our largest customers — and support some of the country’s largest and most important military and defense installations,” Blue said.

The project’s components are being or already have been assembled, and Dominion has taken delivery on many already, with its Jones Act-compliant vessel, the Charybdis, nearly complete and heading to the construction site off the southern coast of Virginia in the next two months to support turbine installation this summer.

“It’s difficult to fully assess the impact tariffs may have to the project’s final cost, as actual costs incurred are dependent upon the tariff requirements and rates, if any, at the time of delivery of the specific component,” Blue said.

So far, components already have cost an extra $4 million, of which Dominion is responsible for $1 million. But that could grow to as much as $510 million, with the firm responsible for $128 million. It already has filed updated costs with Virginia’s State Corporation Commission that show a $123 million impact from tariffs and Dominion responsible for $31 million, with a final project cost estimate of $10.8 billion.

“The updated project cost of $10.8 billion is expected to increase residential customer bills by an average of 4 cents a month over the life of the project,” Blue said.

Generally, the impact of tariffs on Dominion’s business seems manageable, with Blue saying it already had updated its supply-chain practices after the COVID-19 pandemic.

“We think about increasing inventory and ordering thresholds to address longer lead times, ensure that we have multiple sources of supply where it’s appropriate,” Blue said. “We have been placing some orders ahead of tariff effective dates to mitigate cost increases where it’s possible.”

The other big issue facing Dominion is continued growth in Data Center Alley in northern Virginia, the largest data center market in the world. Blue reported no slowdown of interest in adding new facilities to that market.

Dominion recently asked for a rate increase from the SCC, which also included a proposed new customer class for large loads like data centers that requires them to agree to pay for at least 14 years of power consumption, even if they use less. (See Citing Inflation and Load Growth, Dominion asks Virginia for Higher Rates.)

The new rate class applies to customers who use at least 25 MW, and it would apply to 139 separate consumers, of which 131 are data centers, Blue said. The changes are meant to ensure they pay their fair share and that other customers face fewer risks around stranded assets.

“We’ve talked with the data center customers,” Blue said. “We talked with them in preparing this proposed new tariff. I’m sure there will be further conversations during the case, but I think I can say confidently they understand what we’re looking to accomplish here, and the conversations have been very constructive.”

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FERC Approves $180M Annually for RMR Deals with Brandon Shores and Wagner Plants

FERC issued an order approving settlements on reliability must run (RMR) deals that will keep the Brandon Shores Generating Station and the H.A. Wagner Generating Station in Maryland running until May 31, 2029 (ER24-1787 and ER24-1790).

Talen Energy owns both plants, which are located near Baltimore and had sought to retire this year. But PJM found that would have led to reliability issues. Brandon Shores is a 1,289-MW coal plant, and Wagner is an 843-MW oil-fired unit. Now they will run until transmission improvements are ready to replace them reliably.

Brandon Shores is getting $145 million a year and Wagner $35 million, which includes fixed-cost charges, a monthly investment tracker payment to recover spending that’s needed to keep the plants running and a reimbursement mechanism to cover operations and maintenance costs.

Talen entered into settlements with Exelon, PJM, the Maryland PSC, the Southern Maryland Electric Cooperative and the Old Dominion Electric Cooperative on the RMR deals, which cut its initial annual cost from $175 million for Brandon Shores and $40 million for Wagner. Talen will credit market revenues the plants earn back to customers, and it agreed to limits on investments in the plants, which require PJM approval.

PJM said the settlements represent a significant achievement of consensus on issues between Talen and a broad coalition of load parties that will pay for the RMR deals.

The deal was opposed by PJM’s Independent Market Monitor and the Maryland Office of People’s Counsel, who took issue with how the plants determined their sunk costs. Talen was spun off from PPL in 2015, and at that point Brandon Shores was appraised at $648 million. But in 2012, the firm bought both plants for just $372.5 million. The people’s counsel argued that using the higher number amounted to a windfall for Talen.

FERC trial staff countered that the sunk costs are within the just and reasonable range and will be offset by capacity revenues being credited back to customers. And costs would be greater if outages occurred in the area because the plants were retired too soon.

“Under this approach, the commission need not find that the rate is exactly the rate the commission would establish on the merits after litigation,” the order said. “The commission need only find that the overall package, resulting from the give and take of the bargaining which led to the settlement, falls within a broad ambit of various rates which may be just and reasonable.”

Precedent gives the commission a few legal rationales for approving settlements. The one it picked focuses on the end result of the deal and involves a balancing of the benefits with costs and the potential effect of continued litigation.

The deals provide a high degree of certainty to market participants that the units will be available, including a longer RMR (five months more than initially proposed) and fewer circumstances under which Wagner and Brandon Shores can terminate operations. It also gives PJM flexibility to end the RMR deals early if market conditions change.

“This certainty provides value to the settlements, especially in light of the serious reliability concerns at stake without the settlements that could lead to much greater costs overall,” FERC said.