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December 24, 2024

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SPP Stakeholders Endorse Need Dates for Delayed Transmission Projects

SPP stakeholders have endorsed a pair of winter-weather staging dates for transmission projects after two months of discussions and negotiations that delayed their approval by the Board of Directors. 

The Markets and Operations Policy Committee on Dec. 2 voted to endorse the need dates for a pair of projects from the 2024 Integrated Transmission Planning assessment, sending the issue onto the board and its Members Committee for final consideration during their Dec. 9 conference call. 

The board delayed a decision on the projects’ need dates — the earliest that staff identify that a project is needed — during its October meeting over a lack of consensus. (See SPP Board Approves $7.65B ITP, Delays Contentious Issue.) 

SPP staff met three times over eight days in November with the Transmission and Economic Studies working groups to iron out their differences over the staging issue. They held separate discussions on two winter storm-based models, reviewed staging data on the Year 2 Winter Storm Elliott model and agreed on an incremental staging concept to prevent Elliott-level load shed. 

Sunny Raheem, SPP’s director of system planning, said staff’s focus was ensuring stakeholders could review the two models and provide additional education on the staging approach used to determine the projects’ need dates and in-service dates. 

“There was a lot of involvement from the stakeholder groups and being able to make sure those meetings were progressing forward and accurately within the board’s direction,” he said. 

The discussions resulted in MOPC’s endorsement of a December 2028 date for the 345-kV Tobias-Elm Creek transmission line on the western side of SPP’s footprint, an 85-mile segment valued at $887.46 million. It cleared the two-thirds approval threshold with 71%. 

The TWG and ESWG recommended a 2028 need date for the 154-mile, $484.09 million 345-kV Buffalo Gap-Delaware project from Kansas into Southwest Missouri, but Evergy was able to amend the motion to move the need date to December 2025. MOPC eventually approved a motion that included the 2025 need date as resolving the remaining Elliott target area’s reliability needs, consistent with SPP staff’s incremental staging approach. It passed with 75% approval. 

The first project is expected to increase transfer capability from SPP North to SPP South and decrease the chances for load shed. The second brings a new extra-high-voltage source into Missouri to support system voltage and transfers from SPP. 

Evergy’s Mo Awad pressed for the earlier 2025 need date, saying a related 345-kV project with a 2025 need date would not resolve low-voltage issues experienced during Elliott. He said the 2025 date is consistent with staff’s “shorter lead time” approach referenced in an ITP staging process information paper. 

SPP defines projects needed within three years to be “short-term reliability projects.” SPP must explain the reliability issues and post them for a 30-day comment period before the board’s determination. Incumbent transmission owners hold the right of first refusal. 

Rebuild projects in a ROFR state and needed after three years are open to competitive bids under FERC Order 1000. 

“I don’t see any of these projects being in service before the winter of 2028. That’s just the reality of building big transmission projects,” Kansas Power Pool’s Larry Holloway said. “It appears to me that this is just an argument to avoid the competitive process.” 

Awad responded during an extended back-and-forth between the two with several examples of 345-kV projects that Evergy has been able to complete on time and on budget.  

“Those are concrete examples that we complete 345-kV projects by the in-service data as accepted by SPP on the [notification to construct],” Awad said. “I would offer that if those projects go competitive, they’re not going to expedite the projects. They’re going to slow them down. If they’re not competitive, they’re going to go to the [designated transmission owner], and they’re going to start engineering and right-of-way acquisition immediately. If those projects go to the competitive process … it will take a year at least to award the project to an individual. That’s a year that could be used for engineering and right-of-way acquisition.” 

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Power Market Costs Behind Rate Increases, PGE Says

Portland General Electric’s rate hikes largely stem from increased wholesale power market costs, the utility wrote after Sen. Ron Wyden (D-Ore.) voiced concern that customers are struggling to pay their electricity bills. 

PGE CEO Maria Pope responded to Wyden’s questions concerning increased electricity costs in Oregon in a Nov. 27 letter that described the immense growth the utility has seen in tech sector loads but stopped short of tying that development to the price pressures faced by residential ratepayers. 

The Oregon Public Utility Commission (OPUC) approved 40% in price increases for PGE customers from 2020 to 2024, an annual average increase of 8%, according to Pope. 

“These customer price changes over the last five years have primarily been driven by the rising costs to purchase necessary power from the open energy market to serve customers,” Pope wrote. “Power costs, which PGE has limited options to control and are necessary to maintain reliable service to customers, have nearly tripled in the past five years.” 

Pope’s response follows Wyden’s contention in a separate letter that PGE customers’ electricity bills have gone up by at least 40% since 2021, while nonpayment shutoffs have increased.  

“For folks that are walking an economic tightrope, balancing food and medicine bills with electricity prices, the rising prices are unsustainable,” Wyden wrote. 

The lawmaker acknowledged that efforts to modernize the power grid have partly contributed to the price changes but added that “it is concerning to see the cost of electricity rise at this rate in such a short time frame.” 

Wyden sent a list of seven questions to Pope’s office, requesting a response within 30 days. 

Pope got back to the lawmaker two days later, highlighting various factors that have contributed to the price increases over the past four years. The CEO pointed to recent investments in energy facilities and infrastructure, wildfires, heat waves and inflation, among other things. 

Energy deliveries in 2023 were 9.2% higher on a weather-adjusted basis than in 2019. In the 10 years prior, the utility saw growth of 2.8%. Industrial energy deliveries increased by 34.3% in the past five years, mainly driven by semiconductor manufacturing and data center segments, according to the letter. Over the same period, residential load grew by 5.2%, while commercial deliveries declined by 2.7%.  

Wyden asked if PGE has taken steps to limit the cost increases to those sectors that have driven the most growth in the past five years and to explain whether and why residential customers could be bearing the costs for that growth. 

Pope responded that rates for all customer classes are determined through OPUC’s public rate review process based on the utility’s cost of service to each class.   

“Existing regulatory frameworks will need to evolve to appropriately reflect how investments serve different customers and how costs are allocated given the changes in the new large load demands,” she wrote. “Collaboration with regulators, policymakers and stakeholders is essential to help address these new realities and to keep the price of electricity as low as possible for residential and other business customers.” 

‘Keep Pressing the Case’

Wyden also asked about costs not covered under the Inflation Reduction Act of 2022. The act aimed to cover 30% of the cost of new clean energy installations, the lawmaker’s letter stated. 

Pope responded that clean energy resources are not the main culprit behind rate increases, saying that “[t]he cost of power purchased on the market and through the Bonneville Power Administration (BPA) to serve customer demand, address capacity constraints or … fuel thermal plants tripled between 2019 and 2024.” 

“These costs are beyond the utility’s ability to control,” Pope added. “Over that same time, PGE’s own operating expenses underran the rate of inflation by 7%.” 

Doug Johnson, a spokesperson for BPA, told RTO Insider the agency “makes transactions at prevailing market prices and competes in the wholesale market as both a buyer and seller of energy and capacity.” 

“BPA, similar to PGE, has witnessed the value of these energy and capacity products fluctuate with a propensity to rise over the last few years as the demand for clean and reliable power and dispatchable resources has increased,” Johnson said.

“BPA was somewhat surprised to learn it had been singled out in the response letter,” he added.

Meanwhile, Wyden’s staff has contacted the OPUC to ask what else can be done to combat the increases, which exceed national averages, according to Hank Stern, a spokesperson for Wyden. 

“[Wyden] appreciates PGE’s responsiveness to his letter and in addition to the fresh discussions with the PUC about available options, will follow up with PGE to keep pressing the case for fair rates that Oregon consumers can afford,” Stern told RTO Insider. 

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Maryland Offshore Wind Plan Gains Final BOEM Approval

Federal regulators continue to advance offshore wind energy development, issuing a key approval for a Maryland proposal and smoothing the way for as many as six future projects in the New York Bight. 

The Bureau of Ocean Energy Management announced the decisions Dec. 2 and Dec. 3. They are the latest in a long series of such announcements by an administration that made building the U.S. offshore wind industry a priority — and among the last before the transition to a president who has pledged to shut down the industry. 

BOEM on Dec. 3 announced approval of the construction and operations plan for the proposed Maryland Offshore Wind project.  

It is the final BOEM approval needed for the plan. It had been expected after BOEM on Sept. 5 issued a record of decision in favor of US Wind’s proposal to place up to 114 wind turbines rated at up to 2 GW off the northern Maryland coast, near the Delaware border.  

The two-phase plan — called MarWin and Momentum Wind — has secured contracts with the state of Maryland for the offshore renewable energy certificates that will help make the project financially feasible. 

In prepared statements, the developer and an industry association made no mention of the Maryland Offshore Wind’s prospects after President Donald Trump returns to office next month. They also made no mention of the ecological benefits of offshore wind power, focusing instead on energy security and economic benefits, both of which are stated priorities for Trump. 

US Wind CEO Jeff Grybowski said: “This is a proud moment for US Wind. After more than four years of rigorous and robust analysis, we are thrilled to have secured this final BOEM approval. US Wind’s projects will produce massive amounts of homegrown energy and will help satisfy the region’s critical need for more electricity, all while supporting good local jobs. America can achieve energy abundance and put many Americans to work building the power plants of the future.” 

Oceantic Network CEO Liz Burdock said: “Today, Maryland Offshore Wind became the 10th approved commercial-scale project, another significant achievement for the U.S. offshore wind industry. The first project for the state of Maryland, it will deliver a host of economic benefits while helping to meet our nation’s growing energy demand. Maryland Offshore Wind will create American jobs by harnessing a strong, local offshore wind supply chain. US Wind has advanced plans to bring steel fabrication back to the old Bethlehem Steel facility in Dundalk, and the project will support a variety of other industries throughout its life cycle.” 

A day earlier, on Dec. 2, BOEM announced a record of decision identifying 58 environmental measures expected to be applied to projects proposed in the six New York Bight lease areas off the New Jersey-New York coast. 

Wind energy lease areas in the New York Bight are shown. | BOEM

BOEM’s simultaneous review of the six lease areas is a first-of-its-kind attempt to streamline the regulatory process for projects that potentially would have similar impacts and proceed on similar timelines, given their proximity to one another and given that all six leases were awarded in the same 2022 auction. 

As part of this process, BOEM completed a programmatic environmental impact statement in October. The groundwork BOEM is laying now does not confer any approvals, nor does it lock in the process by which future approvals would be granted. 

The six lease areas total nearly 500,000 acres and offer the potential for more than 7 GW of installed generation capacity. 

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$11B Transmission + Generation Plan Canceled in NY

An $11 billion package of transmission and renewable energy investments planned in New York has been canceled. 

The Clean Path New York (CPNY) renewable energy certificate (REC) contract with the state was terminated Nov. 27, and one of the partners in the venture said Dec. 2 the project itself has been abandoned. 

No reason was stated for the cancellation, but CPNY likely encountered the same delays and cost escalations that have bedeviled other energy projects in New York. 

CPNY was envisioned as a way to break the densely populated New York City region’s heavy reliance on aging fossil fuel power generation. 

It was to transmit 3.8 GW of power from 23 new solar and onshore wind projects in rural upstate New York south to the New York City area via a 175-mile underground HVDC line. 

Public- and private-sector officials announced in November 2021 that CPNY and the Champlain Hudson Power Express had been chosen for the new Tier 4 RECs designed to help decarbonize the downstate grid. 

After more than a decade in development, and with an expected price tag now in the $6 billion range, Champlain Hudson is under construction. (See Champlain Hudson Power Project Receives Landmark Delivery.) CPNY, which had expected to start construction in 2024 and enter service in 2027, had not yet been approved. 

CPNY was a public-private collaboration of the New York Power Authority (NYPA) and Forward Power, which is a joint venture of energyRe and Invenergy. 

New York State Energy Research and Development Authority (NYSERDA) notified the Department of Public Service on Nov. 27 that it and CPNY by mutual agreement had terminated the Tier 4 REC contract (Case 15-E-0302). 

The three-sentence notice provided no details, and neither did NYPA or Forward. 

NYPA Vice President of Corporate Communications Lindsay Kryzak said Dec. 2 via email: “The Clean Path project was a public-private collaboration in response to the Tier 4 RFP by NYSERDA. We worked alongside energyRE and Invenergy to continue moving Clean Path forward in the face of changing conditions related to the economics of the project. NYPA will continue to work on modernizing the grid and addressing New York State’s transmission needs to support its long-term goals.” 

Forward Power spokesperson Amy Varghese said via email: “energyRe and Invenergy remain committed to New York’s energy transition. As we continue to advance our portfolio of renewable energy projects across the state, we will evaluate solutions for addressing the largest transmission bottlenecks facing New York’s electric grid in order to deliver reliable and affordable power, good-paying jobs and clean air for the Empire State.” 

CPNY is the latest in a long series of casualties in New York’s legally mandated effort to green its grid. 

In June 2023, the developers of most of New York’s large-scale onshore and offshore renewable energy proposals sought to renegotiate their REC contracts because the cost of construction had soared after they locked in their compensation with the contracts. (See OSW Developers Seeking More Money from New York.) 

CPNY followed up with a petition for more money as well, arguing that it was facing the same economic pinch: 14 of the proposals that made up the generation side of the portfolio already held Tier 1 REC contracts, and the other nine were Tier 1-eligible. (See Clean Path NY Joins Calls for Inflation Adjustment.) 

The Public Service Commission rejected the developers’ request to renegotiate the contracts in October 2023 and CPNY subsequently withdrew its petition. (See NY Rejects Inflation Adjustment for Renewable Projects.)

Developers soon canceled the bulk of the REC contracts New York had signed. They were allowed to rebid their projects into subsequent solicitations, but the state’s portfolio of contracted renewables remains stunted a year later, and state officials expect to miss the 70% renewables by 2030 mandate, perhaps by a wide margin. (See NY Expects to Miss 2030 Renewable Energy Target.) 

Varghese did not provide a requested update on the status of the 23 generation proposals. 

They were not a batch of new proposals drawn up for CPNY. Rather, they were a collection of pre-existing proposals gathered into the CPNY portfolio. And cancellation of a REC contract does not mean cancellation of the project itself, though it almost certainly pushes back the timeline. 

Meanwhile, the complex Tier 4 mechanism itself is gradually taking shape. NYSERDA submitted an implementation plan Oct. 11, four years after Tier 4 was added to the state’s Clean Energy Standard. 

And a new state law gave NYPA a new role as a renewable energy developer in mid-2023, more than a year after its CPNY collaboration was chosen for a Tier 4 contract. 

NYPA is finalizing a strategic plan for 3.5 GW of wind, solar and storage capacity that it would develop on its own or in collaboration with the private sector. It has said the 40 proposals in the plan likely would suffer the same attrition rate as seen in the industry — 80 to 85% for early stage proposals and 30 to 60% for more mature projects. (See NYPA Enters Renewable Development with 3.5-GW Plan and NYPA Urged to Do More in New Renewables Role.) 

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LBNL Report Quantifies Resilience Benefit of Distributed Storage Systems

Installing solar-and-storage systems at customer homes can improve grid resilience, according to a new study from Lawrence Berkeley National Laboratory, which found they cut loss of load by a mean of 96%.

The study crunched the numbers on the value of mitigating loss of load and regional differences in outages that last more than 24 hours from around the country. It calculated a benefit-to-cost ratio (BCR) using those data against the cost of solar-and-storage systems, which found the resilience benefits alone justify an average of 14% of the costs of storage.

The actual resilience benefit to adding storage to solar varies significantly around the U.S., ranging from zero to 58% of the costs. Roughly half of the 2,519 counties studied have a BCR under 0.1, and just 12% of counties have a ratio greater than 0.3, the study says.

Those benefits grow with the frequency of extreme weather events leading to significant outages, a higher value of lost load (VOLL) and in scenarios with lower costs of storage, whether from tax credits or cheaper technology.

“The results demonstrate that, in most counties, resilience benefits alone are insufficient to justify the economic addition of storage to existing PV systems,” the study says. “The coinciding occurrence of higher frequency of resilience events, higher VOLL and lower cost can substantially increase average BCR, but these conditions apply to a smaller set of customers.”

Customers get more than just resilience from solar-plus-storage systems, such as cutting utility bills and leveraging grid services, the paper notes.

VOLL can vary significantly among individual customers, with residents that have medical devices that need electricity, vulnerable household members or sensitive equipment placing a higher value on it than others. The paper accounts for those varying needs with a sensitivity analysis.

The findings indicate that solar plus storage can alleviate the impact of resilience events on customers, especially in areas with a high number of such events.

“In the future, we expect climate change to increase the frequency of extreme weather events and potentially the frequency of interruptions,” the paper says. “Increased electrification of end uses intuitively suggests that customers’ average VOLL will increase: Fulfilling any needs will require electricity, with few substitutes available.”

With the regional disparity of areas more prone to outages and relatively higher VOLLs seeing more benefits from solar plus storage, the paper says customers in those areas should have affordable options to mitigate those impacts.

Utilities can maximize the grid and customer benefits of distributed solar plus storage by offering more granular outage information: detailing specific locations, durations and customer impacts, and making anonymized data public. They can also improve the quantification of VOLL, with the paper suggesting that utilities at least break down the value by customer class and location.

“Hosting capacity analyses and publicly available maps allow developers to target specific areas of the distribution system with value-adding resources,” the report says. “A similar approach could be developed for resilience value, in which a utility would integrate its outage management system data and granular VOLL estimates to quantify areas of the grid in which storage may have a high resilience value.”

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Stakeholders Skeptical of NYISO Performance Penalty Proposal

NYISO stakeholders Nov. 21 expressed skepticism of an ISO proposal to levy financial penalties against underperforming generators, saying it was not developed enough to be voted upon by the end of the year. 

While nonperforming generators must buy out the energy they did not provide in the real-time market based on its day-ahead operating reserves schedule, there is no penalty for nonperformance, NYISO said in presenting its proposed Operating Reserves Performance Penalty to the Installed Capacity Working Group meeting.  

Under the proposal, NYISO would use three metrics to identify consistently underperforming providers of operating reserves: 

    • resource response frequency during emergency conditions and audits;  
    • frequency of underperformance after being scheduled in the day-ahead market to provide operating reserves; and  
    • the real-time energy provided compared to the real-time energy requested, covering generators that are infrequently dispatched. 

“We heard feedback from a number of folks that poor performers should be removed from the market and that folks would like to see us put some additional provisions on how we will effectuate removal from the market for poor performers,” said Nathaniel Gilbraith, NYISO’s manager of energy market design. “What we wanted to do … is lay out some illustrative metrics here today to start the discussion.” 

While no one at the meeting was opposed to the idea of penalties, some said that because the thresholds for the metrics were not well defined, it was hard for them to evaluate if they were fair assessments of poor performance. 

“I think you would want to provide some criteria so that people could understand at what level someone would be disqualified,” said Howard Fromer, director of regulatory affairs for Bayonne Energy Center. “I understand you have the authority today to do it, but there needs to be some distinction.” 

The proposal will be discussed again Dec. 11, with a final draft for stakeholders to vote on before the end of the year, Gilbraith said. 

“I’m struggling to understand why we’re moving forward with a vote on this in December when there seems to be a lot of outstanding questions that may or may not be answered during the manual revision discussions. … It sounds like we’re going to be working on this project next year. What’s the rush?” asked Matthew Schwall, director of regulatory affairs at AlphaGen. “As things stand, I’m inclined to vote ‘no.’” 

Another stakeholder chimed in that they also thought the proposal was “under-baked” and that while they appreciated that NYISO was “under the gun” to get a vote in by the end of the year, it was hard to support a proposal that was not clearly laid out. 

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NYISO Publishes Final RNA Showing Reliability Need for NYC

NYISO announced Nov. 21 that it has published the final, approved version of the 2024 Reliability Needs Assessment, which identifies a reliability need in New York City beginning in 2033. 

The declaration of a reliability need triggers a process in which NYISO solicits solutions, including transmission-based from the local transmission owners, and generation and demand response from market participants. 

The NYISO Board of Directors had approved the final draft several days earlier. (See NYISO Board Approves RNA, 2025 Budget.) The RNA’s assumptions changed throughout the stakeholder process. It initially identified a statewide need, but staff revised their concerns downward after they identified “flexible” loads in the cryptocurrency sector. (See NYISO: Large Load Flexibility Eliminates 2034 Shortfall Concern.) 

Zach Smith, senior vice president of system and resource planning, elaborated on this shift with Kevin Lanahan, vice president of external affairs and corporate communications, on the ISO’s “Power Trends” podcast. 

“We learned partway through this process more details, more operational characteristics of some of these facilities such that we were able to make what we believe is a reasonable assumption that some of these facilities will reduce their demand during these peak demand periods,” Smith said. 

“The statewide reliability need was avoided, but it’s looming, fair to say?” Lanahan prompted. “It still kind of looms in the future.” 

“It sure does. … On a statewide level, we determined that we do not officially have a reliability need on a statewide basis over the next 10 years. … That’s the good news,” Smith said. “However, in 2034, our calculations show that on a statewide basis … we have a surplus of only 50 MW. That’s very small on a system that’s over 30,000 MW of peak demand.” 

With such a small surplus, any small changes in the assumptions about what generation is coming online, and the way that industries draw power, could lead to an official declaration in the short term, Smith said. 

Load Forecasting Task Force Updates

The Load Forecasting Task Force presented preliminary updates to its 2024 weather-normalized peak load for the 2025 ICAP forecast at its meeting Nov. 22. These included both the preliminary weather-normalized peak loads for this year and updated growth factors for each transmission zone based on economic data from Moody’s Analytics. 

This year’s weather-normalized peak load was 31,292.7 MW, which will be factored into next year’s ICAP forecast. It occurred July 8 during the 5 to 6 p.m. hour.  

Max Schuler, a demand forecasting analyst for NYISO, went over the economic indicators for the transmission zones, showing that across the board, real income, GDP, number of households and employment were trending upward, but population was trending downward in each, except in the Orange & Rockland Utilities zone. 

“If households are increasing but population is going down, what does that mean?” asked Howard Fromer, director of regulatory affairs for Bayonne Energy Center. 

“These are all very slight changes for household and population,” Schuler said. “But it’s a continuing trend of fewer people per household … as younger people move out without their parents to start their own house.” 

New York State Reliability Council Installed Capacity Subcommittee

The New York State Reliability Council’s Installed Capacity Subcommittee reviewed and approved updates to the Tan45 Methodology Review Whitepaper and the Installed Capacity Requirement Study technical report. 

The ICAP study shows an increase in required capacity from last year, from 23.1 to 24.4%. Most of this increase was driven by the limit on Emergency Operating Procedure calls. The rest was driven by increases in renewables and Special Case Resources. 

The white paper investigated how the method the NYSRC uses to help set the installed reserve margin will function as new transmission projects come online to serve offshore wind resources. (See NYISO Studying How to Update IRM Calculation to Account for Offshore Wind.) 

It found that under cases in which there are 9,000 MW of new offshore wind resources, the complex method for setting the IRM — known as “Tan45” — is unable to establish an IRM. 

The NYSRC in 2025 will continue to investigate alternative methods, or improvements to the current method, to figure out how to calculate the IRM under evolving conditions. 

Both studies will be sent to the NYSRC Executive Committee for approval in December.  

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MISO Records Comparatively Smaller Peak in October Operations

MISO experienced an 84-GW peak load during an unseasonably warm early October; still, the peak was no match for October 2023’s 99-GW peak.

Despite MISO registering a smaller year-over-year monthly peak, its average October 2024 load remained unchanged from last year at 69 GW, according to the RTO’s monthly operations report. Ahead of the fall, MISO predicted a 95-GW peak during the month.

The system appeared unaffected by an 872-MW capacity deficit for the fall season in Missouri’s Zone 5 due to the permanent closure of Ameren’s Rush Island coal plant Oct. 15. MISO wasn’t forced to issue an alert or warning throughout October. (See MISO Predicts Painless Fall Despite Missouri Capacity Shortfall.)

MISO averaged a $26/MWh real-time locational marginal price during October, less than October 2023’s $31/MWh and half of October 2022’s $52/MWh average. Average coal and gas prices stayed static year-over-year, at $2/MMBtu.

MISO said it fell short of its self-imposed standard on price divergence between its day-ahead and real-time markets over the month. System-wide, the average day-ahead price was $26.71/MWh while the average real-time price was $25.80/MWh.

The RTO usually tries to keep its absolute day-ahead to real-time price difference divided by a day-ahead locational marginal price at or below 22.2%. In October, MISO said the deviation reached 27%.

MISO said congestion and real-time ancillary service product scarcity worsened the divergence. It added that “ramp-up continues to be a challenge, particularly in the evening hours as generation is coming offline.”

The grid operator said day-ahead to real-time price deviation this year also has been poor enough to review in January, April, May, June and July, in addition to October.

For October, real-time congestion cost the footprint about $118 million, lower than October 2023’s $186 million.

Daily average generation outages for the typically maintenance-heavy October climbed to 61 GW this year, compared to 53 GW in October 2023.

As it’s been doing on a nearly monthly basis, MISO set an all-time peak solar supply record Oct. 16, when solar briefly served a little more than 8 GW, or 16% of load at the time. Solar contributions were significant enough to register on MISO’s total 49-TWh energy fuel mix for the month, where they supplied 2 TWh.

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Environmental Nonprofits Argue MISO’s New Capacity Accreditation Missing Key Detail

Four environmental nonprofits insist MISO’s recently approved capacity accreditation is incomplete unless the RTO details how it will conduct its loss of load modeling the new approach relies upon. 

The Sierra Club, Natural Resources Defense Council, Sustainable FERC Project and Fresh Energy on Nov. 25 sought rehearing of MISO’s accreditation, saying FERC seemed to miss a key piece of the puzzle when it authorized MISO’s new capacity accreditation method without forcing the RTO to codify and then update its loss of load expectation modeling process in its tariff (ER24-1638). 

FERC in late October approved MISO’s capacity accreditation, which blends the historical performance of individual generators with a probabilistic performance during simulated loss-of-load events. (See FERC Approves New MISO Probabilistic Capacity Accreditation.) The RTO plans to draw on its loss of load expectation (LOLE) analysis to estimate the hours across a year that the system is likely to experience a deficit or dwindling margins and compare those to when its resource classes are expected to be available.  

The four nonprofits contend that FERC failed to appreciate how significant MISO’s LOLE modeling will be to the accreditation.  

“The key inputs and assumptions that MISO uses for the LOLE model have major effects on accreditation outcomes and rates. Neither the commission nor stakeholders can determine whether the RTO’s accreditation scheme will actually produce just and reasonable rates without reviewing those significant modeling choices,” the groups argued.  

They also said the consequences of not vetting LOLE modeling stand to be “severe,” with FERC potentially “abdicating” its responsibility to ensure reasonable rates and MISO wielding “unchecked discretion to alter … key components to change rate outcomes without commission scrutiny.” 

The groups disagreed with FERC that MISO including a description of its LOLE modeling process is merely an “implementation detail.” They said the RTO’s LOLE modeling process contains “several discretionary judgments” and could alter accreditation and significantly affect rates. 

For instance, MISO’s LOLE modeling at present includes a cold weather outage adder, they said, which attempts to capture thermal resources’ outage risks in winter and could dent those resources’ accreditation values. They also said it is working on a new LOLE model for its storage resources, and staff so far in public stakeholder meetings have presented modeling approaches that produce wildly different outcomes.  

The four further argued that the inputs and assumptions to MISO’s LOLE model “are not generally understood in any contractual arrangement such that recitation would be superfluous.” They pointed to the RTO’s existing reference to its LOLE modeling in its tariff and said that “barebones” description “implies nothing about how MISO generates probability distributions for variables such as demand, generator performance, storage availability or external import availability.” They also said MISO doesn’t specify how it assesses “potential load growth or expected changes in the installed resource mix prior to a given delivery year” to influence the modeling.  

“As a direct result of its accreditation choices, MISO has ensured that LOLE modeling choices are specifiable practices that significantly affect rates. Yet MISO’s tariff implies almost nothing about what discretionary modeling methods MISO will adopt within the very complex LOLE analytical space,” the groups summed up. “To facilitate just and reasonable rates, FERC should ensure that stakeholders have full visibility into MISO’s LOLE model as soon as possible so that they can work with MISO to refine the model toward optimized predictive power.”  

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Pennsylvania PUC Examines PJM’s Tightening Reserve Margin

Pennsylvania is a net exporter of electricity, but the narrowing reserve margin in PJM led the state’s Public Utility Commission to hold an all-day technical conference Nov. 25 to discuss resource adequacy.

While this past summer’s capacity auction showed spiking prices amid rising demand and retiring power plants, PUC Vice Chair Kimberly Barrow said she started focusing more on resource adequacy during winter weather events like the polar vortex a decade ago and Winter Storm Elliott in December 2022. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

“What I’m very worried about now is those challenges occurred at a time when we were not facing the kind of load growth that we’re facing right now,” Barrow said. “The load growth we’re facing is unprecedented, and I do not know if we are bringing resources on quick enough to face that load growth.”

Pennsylvania is a restructured state, so the PUC has limited authority over power generation, but it is still responsible for ensuring reliability and affordability on the distribution system, she added.

Demand growth, driven mostly by large data centers coming online, is working alongside retiring power plants and a slow pace of adding new supplies to cut into what for years was a healthy reserve margin, PJM Executive Vice President Stu Bresler said.

“PJM really started in an enviable position, from the standpoint of the reserves that we had available in the system than we do today, but these trends that we are seeing, obviously, are causing that to change and change significantly,” Bresler said. “Overall, we believe that the structure of our wholesale electricity markets remains sound. We believe that those markets will continue to stimulate resource development and resource additions.”

But there is going to be a transitional period with narrow reserve margins, as evidenced by the last capacity auction, he added. PJM’s adoption of effective load-carrying capability (ELCC) to measure resources’ capacity also contributed to the last auction’s outcome, but Bresler said that method should encourage the kind of firmer resources the grid needs going forward.

PJM Independent Market Monitor Joe Bowring said properly designed ELCC rules would help the region maintain reliability, but it and other rules should be changed.

“I don’t think the current design will get us there, but I think that we need to move forward and do a rethink of ELCC and make it more sophisticated at the point where it really will reflect supply and demand,” Bowring said.

ELCC has an “excessive” focus on natural gas plants’ performance during several historical hours in winters when PJM was still learning about gas notification periods, Bowring said. The rule understates the value of thermal resources, especially combined cycle natural gas plants and combustion turbines.

While Pennsylvania has restructured, that does not mean the industry relies entirely on PJM’s wholesale power markets for its revenue, said Travis Kavulla, NRG Energy vice president of regulatory affairs.

NRG owns generation and a competitive retail business that serves about 10% of the demand in the Eastern restructured markets, which means it must hedge the latter with bilateral contracts with generators, he said.

“NRG, when it signs up a retail customer, engages in a policy called back-to-back hedging. On Day 1 of our service under that contract, we estimate a customer’s load, make adjustments for extreme weather and then bilaterally buy energy supply that covers that estimated load on the part of the customer,” Kavulla said. “These bilateral contracts are a major source of revenue to our counterparties, the power plants of PJM.”

Sometimes those bilateral contracts can be more important to generators — though less visible to the public — than income from PJM’s markets, he added.

“These markets were designed with the idea that the bulk of trades would be bilateral transactions and self-supply,” Bresler said. “It was not intended that either suppliers would invest, or consumers would ride the spot market based on spot market prices. The fact of the matter is, though, these markets are unforgiving.”

PJM’s goal is not for prices to be high, but to signal the market that supply is needed, which will encourage suppliers and customers to enter into new long-term contracts, he added.

Kavulla said one thing the PUC could do under its authority would be to encourage longer-term contracts in the retail market. Even residential customers can get prices locked in for five years, at lower rates than default service.

One major recent example of those bilateral deals directly leading to new supply on the grid was the contract Constellation Energy struck with Microsoft to bring Three Mile Island’s recently retired reactor back to service to supply a new data center, said Adrien Ford, Constellation’s director of wholesale market development.

“It’s our partnership with Microsoft that’s bringing the Crane Clean Energy Center back online,” she said, referring to TMI’s new name, “not the PJM one-year print.”

Another way Constellation hedges its generation is by participating in the default service auctions that restructured states run, which secure supply for most small customers that do not shop for competitive supply, she said.

Policy Changes and the Supply Chain

With a new political party taking over the White House and EPA, some of the retirements that PJM has been forecasting could be significantly delayed, said Calpine’s Joe Kerecman.

EPA’s plans to regulate carbon dioxide will certainly change with the new administration, and other rules could also be tossed out, which will mean existing coal plants stay running longer.

That could help because Kerecman and other representatives of independent power producers noted that building new natural gas plants takes longer than it used to.

“I think you can get gas turbine deliveries by 2027 certainly. … You got to write some big checks, which differentiates a company like Calpine, because we have 27,000 MW,” Kerecman said. “We have well established relationships with [original equipment manufacturers] and EPC [engineering, procurement and construction] contractors as well.”

The domestic industry has to compete with growing demand for power plant equipment from the Middle East, along with generally stressed supply chains, he added.

If a developer sent the first milestone payments to an OEM now, they would not get delivery of equipment until mid- to late 2028, and then it would need to spend an additional 12 to 18 months actually building a power plant, Talen Energy Chief Development Officer Darren Olagues said.

“It’s obviously a global queue, but it’s one of the reasons we need to get this right now and inspire the confidence for developers to start to put down the milestone payments,” Olagues said. “You’re talking tens of millions of dollars per turbine.”

It’s also hard to plan for a power plant with continuous discussions about changing PJM’s capacity market, he added.

The industry’s bankers would “love a steadier signal,” LS Power Senior Vice President Marjorie Philips said.

“But I think there’s a couple of things to think about,” Philips said. “One is, the data centers are ignoring the capacity markets. They are paying astronomically more. There’s a reason why we are all looking to supply them. They value the electricity a lot more than we’re valuing it in the capacity market.”

The other factor is that constant regulatory interventions in the market do not help build investor confidence, she added.

“The commodity fluctuations are less troubling than the regulatory interventions,” Philips said. “But I think long term, if we let the market work and understanding that it’s very unpalatable that we’re going to have to deal with high prices, and that, candidly, falls on your shoulders, how to manage the retail rates, and we are not unsympathetic to it, but that is the political reality.”

It takes “two or three” price signals for developers to invest in new supply as they have in the past, she added.

Potential State Responses

While Pennsylvania is a restructured state, Consumer Advocate Patrick Cicero said it was still the PUC’s responsibility to ensure resource adequacy.

“I would just submit that I think that no one should question that is the job of the Public Utility Commission,” Cicero said.

State law requires the PUC to ensure reliable, affordable electricity, and part of that includes the generation issue facing the PJM region, he added.

“The fact that we’re a restructured state means that generation is no longer rate regulated, but it does not mean that the Public Utility Commission does not have the authority and tools necessary to ensure continued reliability,” Cicero said. “I assure you that if something happens, you will be blamed, and so consequently, if you will be blamed, then you should have the tools necessary to fix this problem.”

PJM’s market is not a failure, but it is leading to resource adequacy problems for Pennsylvania right now, PPL Electric Utilities President Christine Martin said.

“I really do think that we need to keep an open mind [and] not let the past dictate the future; not let a law passed almost 30 years ago define our future,” Martin said.

PPL supports changing the law to allow utilities to invest in generation, but Martin said that would not have to completely upturn Pennsylvania’s history with the markets. It is mainly focused on getting new resources online in the commonwealth.

“We are not insulated from Maryland or New Jersey or Delaware or D.C.,” Martin said. “We don’t have that luxury. So, when we think about resource adequacy and economic development and keeping the lights on, the type of generation [and] the location of generation does matter.”

GT Power Group President Glen Thomas, a former Pennsylvania PUC chair, cautioned commissioners from turning away from the markets too quickly. Given that generation investments are lumpy, PJM has faced these kinds of debates in the past — including 15 years ago when Maryland and New Jersey tried to get new natural gas built with state-backed contracts, which were ultimately found unconstitutional by the U.S. Supreme Court.

One of the contracts that New Jersey signed would have paid a plant $286 to $432/MW-day, well above the $270/MW-day the last auction capacity auction cleared at, Thomas said. It would have added over $1 billion over the term of the contract, which proved unneeded as the three plants New Jersey tried to support are all still operating today without any subsidies.

“They made a very critical mistake that would have cost their consumers a lot of money, but for the fact it was litigated and determined to be unconstitutional,” Thomas said. “So, it’s great to think about these plans. It’s great to think about the future, but it’s very hard to predict the future with these markets. These markets are cyclical.”