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November 26, 2024

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SPP Markets & Operations Policy Committee Briefs: Oct. 15-16, 2024

LITTLE ROCK, Ark. — SPP says it is devoting significant resources to finally resolve Attachment Z2, a bone of contention among SPP stakeholders since 2016, by the end of this decade. 

General Counsel Paul Suskie told the Markets and Operations Policy Committee on Oct. 15 that it will take 24,000 hours of staff time and nearly $2 million to finally resettle Z2 refunds and resettlements following a pivot by FERC in ordering SPP to reverse its previously approved invoicing process. 

“Think through this: It took us from 2008 to 2016 to create the Z2 process. Now we have to undo it and recreate it and resettle going back to 2015,” Suskie told MOPC. “Luckily, we have a lot of knowledge and expertise and processes that will make that easier than it was to create it, but it is a significant undertaking that will probably take until 2029 to complete.” 

Under Attachment Z2, transmission upgrade sponsors receive credits from any upgrade users whose service could not be provided “but for” the upgrade. The attachment also requires the RTO to invoice the charges monthly and to make any adjustments within one year. 

However, software problems delayed the attachment’s final implementation for eight years before 2016, during which the RTO did not invoice for the upgrade charges. FERC approved a waiver request to settle more than 365 days in arrears, but in 2019, the commission reversed course and said SPP should have settled Z2 from only September 2015 forward. (See FERC Reverses Waiver on SPP’s Z2 Obligations.) 

By then, SPP already back-billed market participants $138 million, not including interest, in 2016 and continued to use Z2 credits at the same time. It has applied $503 million in Z2 credits since 2015. 

“Because this is a process [where] each payment impacts other payments, what we’re doing today is in error because FERC reversed what they did from 2008 to 2015,” Suskie said, noting it will require recalculating each operating day since September 2015 to undo and refund the historical settlement. 

Several members filed Section 206 complaints against SPP over the Z2 resettlements. In 2022, the grid operator filed an update to its proposed refund plan from 2019. It urged FERC not to order refunds until all litigation is final. (See 8th Circuit Denies Review of FERC Orders on SPP Attachment Z2.) 

SPP’s Michael Desselle, who is retiring, is given a standing ovation by the Strategic Planning Committee. | © RTO Insider LLC

Suskie said the commission has been clear that the RTO is not to process refunds without a FERC order. Left in limbo are individual refunds totaling $147 million, plus $33.4 million in interest, due to transmission customers from 2008 to 2015.  

SPP is developing an interim software solution to calculate and distribute resettlements on activity from September 2015 until the production system can be used. It expects to have resettlements in sync with routine monthly settlements by 2029. That will require unwinding more than $20 billion in previous settlements to resettle Z2 activity; only 1 to 2% of all resettlements will be related to Z2, staff said.  

SPP emailed estimates of the refunds owed and/or that will be received after the MOPC meeting. The grid operator has created a Z2 website and is building an email distribution list to keep stakeholders updated.

SPP Modifies GI Backlog Process

SPP has modified its approach to clearing the backlog in its generator interconnection queue that dates back to 2018, revising the methodology to improve the accuracy of studies and restudies.  

“That just made more sense and provided more accurate results at the time than when we filed [at FERC] for the backlog plan,” SPP’s Jennifer Swierczek said. “We realized that doing that many clusters at once, customers might not have all the information they needed to proceed to the facility study and the [generator interconnection agreement],”  

The grid operator has added a planned restudy after each cluster’s first two definitive interconnection system impact studies (DISIS). A facility study and the execution of the GIA follow the restudy. 

The backlog initially included four clusters, from 2018 through 2021. SPP planned to keep the 2022 window open “so the line didn’t get longer behind us,” Swierczek said, but a record number of requests forced the RTO to shut down the cluster and add it to the backlog. The same thing happened in 2023 when its 129 requests exceeded those of the previous year’s 108. 

The 2024 cluster will be handled under the RTO’s normal process, but the grid operator has requested a waiver from FERC to extend the 2024 cluster study’s close from Oct. 31 to March 1, 2024.  

SPP began tackling the backlog in 2022 with the 2018 cluster. The queue contained 1,139 active requests for 221 GW of capacity at the time; it now has 395 active requests for 82 GW of capacity. The RTO has executed 48 new GIAs for 7.75 GW of capacity during the backlog work. 

Swierczek said the 2017 cluster, which is not part of the backlog, and the first 2018 study group have 91 projects between them, most of which she said are healthy. Large numbers of withdrawals in other clusters will have to be addressed in their next DISIS phase, with all backlog clusters ready for restudies by next summer, she said. 

Separately, members approved a proposed revision (RR651) to the GI manual allowing upgrades approved mid-DISIS study from other planning processes to be considered as potential mitigations for constraints identified during the ongoing study. SPP says constraint mitigations identified in the study process will be provided by solutions that have been approved and reduce the need for restudies due to withdrawals.

New MOPC Leadership, Members

The meeting was the last for ITC Holdings’ Alan Myers after two years as MOPC chair. 

“He’s done a great job over the last two years, and I’m looking forward to see what he has to close this out with,” said Lanny Nickell, Myers’ staff secretary. 

ITC Holdings’ Alan Myers (right) chairs his last MOPC meeting. | © RTO Insider LLC

“It has truly been my privilege to lead this group for two years,” Myers said after a round of applause, thanking members for their recognition. Then, true to his nature, he said, “Let’s dive in.” 

Omaha Public Power District’s Joe Lang will assume the chairmanship in January. 

MOPC added two new members: Ozarks Electric Cooperative’s Derrick Redfearn and Viridon Southwest’s Neeya Toleman. A Blackstone company, Viridon develops transmission projects in SPP.

Curing LREs’ RAR Deficiencies

Members easily endorsed three revision requests in separate votes.  

The Supply Adequacy Working Group’s proposal (RR632) giving load-responsible entities several more weeks to address deficiencies in meeting their resource adequacy requirement. LREs would have from March 15 to May 15 (an additional 30 days) to cure summer season deficiencies and from Sept. 15 to Nov. 15 (15 extra days) to resolve winter season deficiencies. 

SAWG’s vote to delay a revision request (RR642) until SPP completes its load-hosting capacity tool (LHCT) next year, giving applicable transmission owners three months to review the tool’s data. SAWG is working to implement the Holistic Integrated Tariff Teams’ directive to modify Attachment AQ of the tariff so SPP can proactively perform analysis to determine how much load can be accommodated at each node on the system without incremental investment (load hosting capacity assessment). 

The Market Working Group’s recommendation (RR638) to remove the exemption for day-ahead reliability unit commitment self-commits. It said the removal will mitigate market manipulation by resources intentionally switching between “self” status and “market” status to increase their make-whole payments and help the market reach a more economical solution with more accurate information. 

MOPC’s consent agenda included SPP’s annual violation relaxation limit analysis; the Project Cost Working Group’s in-service date delay report; the 2025 Integrated Transmission Planning assessment scope; and nine RRs that, if approved by the Board of Directors, would: 

    • RR545: Add language clarifying the objectives and initiation of a high-priority study and provide additional flexibility when developing the scope by removing the requirement to perform economic analysis and expanding on the current requirement to only conform to the ITP Planning Manual’s requirements. 
    • RR630: Add Tri-State Generation and Transmission’s various zones in the Western Interconnection to zones that will be a part of the SPP West Region. 
    • RR641: Clarify that self-committing resources contributing to the make-whole payment distribution volume is not only referring to energy storage resources but to all resource types. 
    • RR644: Remove expired or terminated grandfathered agreements from the list of GFAs and update any termination dates or any changes in buying or selling parties as part of the annual update. 
    • RR645: Update the ITP manual by considering aging infrastructure in transmission planning solutions by accounting for avoided or deferred reliability transmission facilities and aging infrastructure replacement. 
    • RR646: Update the ITP manual’s contingency screening criteria in the constraint assessment from 25% loading to 10% loading for 200-kV and above systems. 
    • RR647: Increase the cap under Schedule 1-A (Recoverable Costs) from $0.465/MWh to $0.515/MWh.  
    • RR648: Remove the regulation-up and regulation-down mileage factors from the applicable mitigated offer calculation and clarify terminology to match the supporting calculation for uncompensated costs for offline uncertainty. 
    • RR649: Add value to the network resource interconnection service (NRIS) product by creating an expedited process for designating new network and designated resources outside of the aggregate transmission service study process. It also would revise the generator interconnection study process for new NRIS requests, define deliverability areas and allow existing resources that meet eligibility requirements to use the expedited process.  
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Agencies Describe a Year of Iran Cyber Attacks

Cyber actors backed by Iran have been attacking critical infrastructure providers in the U.S. and other countries for more than a year, hitting sectors including energy, government and information technology, intelligence agencies from multiple countries said.

The warning about Iranian cyber activities came in an advisory released Oct. 16 by the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) and endorsed by the FBI, the National Security Agency and their counterparts in Canada and Australia. The agencies described tactics that the Iran-supported actors have used since October 2023, as observed in “FBI engagements with entities impacted by” the attacks.

Several approaches are documented in the report. Attackers gain initial access to target networks through brute force techniques such as password spraying, in which they use the same password against many different user accounts. If the user account has multi-factor authentication enabled, the attacker will bypass the safeguard by “push bombing” the account, hitting the user with multiple MFA notifications until they approve the request by accident or stop notifications.

Once they have entered the network, attackers often register MFA in their names to protect their access. The agencies observed two cases in which intruders took over an account with uncompleted MFA registration and set it to their own devices.

Discovering the attackers’ presence in a compromised system can be difficult because they make use of living off the land techniques to blend in with normal system activities. Cyber experts have seen these techniques used increasingly by actors linked to China — particularly the Volt Typhoon group — to infiltrate U.S. critical infrastructure organizations. (See China Preparing to ‘Wreak Havoc’ on US, Cyber Officials Warn.)

The agencies recommended reviewing authentication logs for multiple failed login attempts to valid accounts. To detect the use of compromised credentials, agencies said entities could look for a single IP address being used for multiple accounts, or cases of “impossible travel” when a single account shows logins from multiple IP addresses with significant geographic distances.

Mitigations include disabling user accounts and system access for departed staff, continuously reviewing MFA settings to ensure all active internet-facing protocols are covered and ensuring password policies align with relevant guidelines from the National Institute of Standards and Technology. The advisory also recommended that software manufacturers incorporate security by design principles to protect against actors using compromised credentials.

CISA and the other agencies said it is likely the Iranian actors’ goal is “to obtain credentials and information … that can then be sold to enable access to cybercriminals.” They did not indicate that they believe these particular attackers aim to disrupt the critical infrastructure providers themselves.

However, Iran has a longstanding place in U.S. security experts’ minds. The country’s history of “aggressive cyber operations” earned it an entry in the Director of National Intelligence’s 2024 Annual Threat Assessment, which noted that “Iran is willing to target countries with stronger cyber capabilities than itself.”

While many of Iran’s cyber operations are aimed at Israel and other rivals in the Middle East, the DNI observed that it has targeted the U.S. in the past. In 2020, cyber actors linked with Iran tried to interfere in the U.S. presidential election by attempting to obtain voter information, sending threatening emails to voters and spreading disinformation. The director said they may attempt to do so again in 2024.

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BOEM Completes Assessment of Future NY Bight Wind Farms

Federal regulators have completed their first-ever regional environmental analysis of future offshore wind farms that have not yet been proposed. 

The Bureau of Ocean Energy Management’s programmatic environmental impact statement (PEIS) looks at six wind lease areas covering nearly a half-million acres in the New York Bight. 

Because all six areas were leased in the same 2022 auction, BOEM concluded that the leaseholders would be likely to submit their construction and operation plans on a similar time frame. Because all six are in close proximity off the New York-New Jersey coast, BOEM concluded the environmental considerations are likely to be very similar. 

Each construction and operation plan submitted for an individual wind farm still would require individual review and approval by BOEM, but the PEIS is intended to speed up those reviews by reducing redundancies. 

BOEM said this will help developers meet the offshore wind goals set by the Biden administration (30 GW by 2030), New York (9 GW by 2035) and New Jersey (11 GW by 2040).  

The six lease areas hold the potential for 5.6 GW to 7 GW of generation, BOEM said, using a conservative ratio of 3 MW per square kilometer. 

The PEIS assumes placement of 1,103 wind turbine generators with rotor tips stretching up to 1,312 feet above the ocean, 22 offshore substations, 44 export cables totaling 1,772 miles and 1,582 miles of inter-array cables across the six lease areas. 

The PEIS lists a series of predicted effects from these potential future offshore wind farms. Most are similar to the effects predicted in individual environmental impact statements BOEM has prepared for wind farms proposed off the Northeast coast, except that in this case, the impact could vary depending on whether it was one project or six being measured. 

And as with the other statements, the PEIS is imprecise in some of its predictions — a specific metric could be better, worse or unchanged after a forest of thousand-foot turbines is installed nearby. 

The impact on benthic resources, invertebrates and fish habitat could range from moderate beneficial to major detrimental, for example. The negative effects on commercial fisheries and the critically endangered North Atlantic right whale could be negligible, moderate or major. Major negative impact is expected on cultural resources, navigation and vessel traffic. The view from the shore might be minimally affected, and it might suffer a major negative impact. 

As with other projects, there is projected to be a major negative impact on scientific research and surveys, which of course would complicate efforts to quantify some of the other impacts as the wind farm is built and begins operating. 

BOEM released a draft of the PEIS in January. It said input received in the subsequent comment period was considered for inclusion in the final PEIS released Oct. 21. 

In a news release, BOEM Director Elizabeth Klein said: “We appreciate the feedback we have received, and we believe our regional approach will provide a solid baseline for future environmental reviews for any proposed offshore wind projects in the New York Bight.” 

There are other wind lease areas in the New York Bight, but these six were sold at the same auction in February 2022, at an early high point for the burgeoning U.S. offshore wind sector. 

The industry was racing forward with support from the federal government and multiple states and had not yet been slammed by the financial and logistic challenges that would, over the next two years, result in the cancellation of most of the offtake contracts for the early Northeast projects and a timeout for some. 

As such, the 2022 New York Bight auction drew $4.37 billion in bids — the nation’s highest-grossing offshore energy lease ever, including for fossil fuels. 

The winners were: 

    • Atlantic Shores Offshore Wind Bight, OCS-A 0541; 
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FERC Commissioner See Explains Her Regulatory Philosophy at EBA

WASHINGTON, D.C. — FERC Commissioner Lindsay See took office the day the Supreme Court issued its Loper Bright decision striking down the Chevron deference to federal agencies, she told the Energy Bar Association’s Mid-Year Energy Forum on Oct. 18. (See Supreme Court Ends Chevron Deference to Administrative Agencies.) 

Under Chevron, the courts had given deference to regulatory agencies’ areas of expertise when their governing statutes were unclear on a subject; the decision reclaimed that legislative interpreter role for the courts.  

“I would like to think that’s not causally related, that suddenly there was concern that a new federal regulator should not have that sort of discretion and deference to the decisions,” See joked. “But it’s certainly a sobering time to be a federal regulator. We have so many of these shifting legal frameworks and standards in place, and this is also, of course, kind of great transition in the industry as a whole.” 

See developed an expertise in energy by working as the solicitor general for West Virginia, which involved litigating many energy cases due to the state’s economy and its attorney general’s priorities. It has been four months since See transitioned from a state litigator to a federal regulator, she said. 

“I have been thinking an awful lot about the difference between [what] spurs FERC’s reactive and proactive authorities,” See said. 

The bulk of FERC’s work is reactive — it must respond to filings by the industry it regulates, whether changing a market rule, setting rates or siting gas infrastructure. The proactive side comes when FERC issues a broader rulemaking that can change how the industry it oversees operates. 

“At least from an outsider’s perspective, when I think about agency work, I think I immediately jump to that second one, to the more proactive policy-making role,” See said. “And that’s not actually the heart of what we do at FERC. So I have been spending a lot of time these first few months really trying to get that first part, to do it well and to really understand that piece.” 

While she is in a different role at FERC, the reactive piece is like the legal work she was doing as solicitor general: It often involves multiple parties with different views arguing about the evidence in a docket, and it builds up precedent that future cases are expected to follow. 

The reactive role of FERC is limited because it cannot control what comes before and it also cannot separate out parts of a filing that it likes, approving those and denying others, See said. 

“I think especially in a time of dynamic change, sometimes incremental change isn’t enough, and there is a need for a more holistic solution that’s able to work more broadly,” See said. 

That is where FERC’s more proactive, rulemaking authority comes into play, and See said she has been thinking about it, noting that it differs greatly from her previous role as a state litigator. 

“I think there’s a lot of wisdom as well in making sure that the cost of that change is actually worth the benefit, and not just acting for the sake of acting,” See said. “Because taking a lot of time to study and think, and then if the conclusion at the end is actually it’s better for X, Y, Z reasons to stay where we are that can look like not actually doing our job.” 

Often change is worth the cost, she said, but that is a test she plans to apply to that proactive role in her new job. Another key to the proactive role is getting a wide range of detailed comments on any potential rule changes. 

“I have a real respect for that process because of the different perspectives and voices that can inform those decisions, because I want to make sure that we’re thinking as best we can,” See said. “What are some of the unintended consequences [regarding] a shift in one direction or another? How is that going to play out on the ground?” 

Being outside the contested case model seeing how a final decision will actually impact the real world is more difficult, but the more commenters that file the easier it is for regulators to figure out what will happen. 

“I think that having sort of a partnership model of listening to different voices and perspectives is what can make the sort of proactive role, that has such a critical and important space at the time we are now, can make that really effective,” See said. 

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PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report

The PJM Independent Market Monitor released the second iteration of its report on the 2025/26 Base Residual Auction, digging deeper into the impact of excluding reliability-must-run (RMR) resources from the capacity market.

The report ran a sensitivity modeling the Brandon Shores and H.A. Wagner generators as offering capacity into PJM’s supply stack, along with including capacity offers from all intermittent and storage resources categorically exempt from the capacity must-offer requirement.

The report found that combining the two led to a 53.9% increase in total capacity costs, amounting to about $5.14 billion. The two generators, owned by Talen Energy, were not required to offer into the 2025/26 auction as they will be operating on an RMR contract. (See PJM Requests 2nd Talen Generator Delay Retirement.)

The second sensitivity analyzed the effect of limiting combustion turbines and combined cycle generators to their summer ratings when PJM’s risk modeling is concentrating risk in the winter, paired with modeling the expected output of the two RMR generators. The analysis estimated that the two led to a 77.6% increase in capacity costs, or about $6.42 billion.

Combining the three components — excluding the two RMR units, and categorically exempt resources from the capacity market and capping gas generation at summer ratings — corresponded with auction prices being 108.1% higher, or a $7.63 billion increase.

The Monitor argued that exempting resource classes from participating in the capacity market and not modeling RMR units allows generation owners to limit access to transmission that could be used by other resources to deliver capacity and create significant differences in the supply stack year-to-year. It argued that the risk of an intermittent capacity resource being subject to capacity performance (CP) penalties for being offline during an emergency at a time when it could not respond could be countered by accounting for availability when assessing performance.

“The inclusion of a must-offer obligation for categorically exempt intermittent and capacity storage resources should be coupled with the removal of (performance assessment interval) penalty liability for such resources when it is not physically possible to perform,” the Monitor wrote. “The capacity market has included balanced must-buy and must-sell obligations from its inception. The current rules can and should be changed to restore that balance.”

During the Organization of PJM States Inc. (OPSI) annual meeting Oct. 21, Monitor Joe Bowring said capacity interconnection rights (CIRs) are a scarce resource that control access to the grid for generators. He argued that those holding CIRs should be required to exercise them.

PJM Executive Vice President of Market Services and Strategy Stu Bresler responded that it would not make sense to count on resources that cannot perform when there’s an auction with an annual commitment to perform. Exempting intermittents from the CP construct would be trading one set of exemptions for another, he said. Instead, PJM is committed in the long term to designing a more granular, seasonal capacity market structure.

The Monitor’s report also recommended expanding the granularity of PJM’s effective load carrying capability (ELCC) accreditation to include hourly data, so that unit-specific accreditation can be implemented, replacing class accreditation with a system of paying resources to be available on an hourly basis, and untying accreditation and summer ratings to allow winter CIRs to determine capability when risk is concentrated in the winter.

“The need for the energy from capacity is not limited to one peak hour or five peak hours. Customers require energy from capacity resources all 8,760 hours per year,” the Monitor wrote. “Rather than develop a complicated seasonal capacity market based on an arbitrary definition of seasons, the hourly value of the energy from capacity should be explicitly recognized in the capacity market.”

The total impact the changes PJM made on the auction led prices to be around double what they would be based on supply and demand fundamentals alone, Bowring said.

PJM Defends Capacity Market Design in Response to Part A of IMM Report

In its Oct. 11 response to the initial portion of the Monitor’s report, PJM argued that while the underlying analysis in the report appeared to be largely correct, the Monitor drew incorrect conclusions and omitted necessary context in its recommendations.

“PJM also does not take exception to the results of the simulations the IMM conducted as they are summarized in the report. They are directionally consistent with those that would be expected given the inputs used,” PJM wrote. “However, the IMM presents an incomplete set of sensitivities, provides insufficient context, and draws several conclusions that either lack support or are incorrect.”

The Monitor’s analysis, released Sept. 20, modeled four sensitivities looking at the impacts of PJM’s marginal ELCC accreditation methodology, exempting generators operating on RMR agreements from being required to offer into the auction, capping accreditation at resources’ summer ratings, and not subjecting intermittent and storage resources to the must-offer requirement.

The Monitor wrote that shifting generation accreditation from equivalent demand forced outage rate (EFORd) to marginal ELCC led to a 49.1% increase in total capacity costs, a finding PJM said conflates the changes made to accreditation and risk modeling. PJM said its revised risk modeling approach accounted for the bulk of the increased capacity costs associated with a market redesign approved by FERC in January 2024 following the Critical Issue Fast Path (CIFP) process conducted last year. (See FERC Approves 1st PJM Proposal out of CIFP.)

“The IMM does not estimate sensitivities capable of differentiating the impacts of these distinct market rule changes, but nevertheless attributes the impact to ‘PJM’s ELCC approach’ and ‘the ELCC availability metric,’” PJM wrote.

PJM went on to defend the marginal ELCC approach, stating that the probabilistic modeling at its core is becoming industry standard, with variants approved by FERC for implementation in MISO and NYISO, with ISO-NE considering similar changes. It argued the EFORd approach of using average availability to determine accreditation predominantly incentivizes performance throughout the year without sufficient focus on high-risk periods.

“Under the tight supply-demand conditions that materialized for the 2025/26 BRA, even relatively small impacts to the supply-demand balance can have outsized impacts on clearing prices because of the inelasticity of both supply and demand,” PJM wrote. “PJM believes that the nearly 2.7 GW impact of the enhanced risk modeling and concordant accreditation changes were appropriate and necessary to reflect emerging patterns of risk and lower-than-expected generator performance during such risk events.”

While the Monitor argued that PJM’s practice of modeling the expected output of RMR units when determining capacity transfer between zones is inconsistent with not including those resources in the supply stack, PJM stated that it views the issue as secondary to recognizing the disparities between capacity resource obligations and RMR agreements. Those contracts require units to operate during limited operational events and carry different obligations from capacity that are incomparable to capacity obligations, PJM said.

The response said more analysis is needed to determine the impact of using winter ratings for gas resources. Adding capacity to high-risk winter hours could shift ELCC weighting toward the summer, where high loads are a greater driver than forced outage rates. That could have the effect of pushing the reliability requirement higher.

PJM said the Monitor’s allegation that intermittent resources could be engaged in market manipulation by withholding their capacity is unsupported and misses valid reasons generation owners may not exercise the must-offer exception.

“The report fails to consider legitimate reasons why exempt resources may not have been offered into the capacity market. … Specifically, PJM believes that the IMM must assess the portfolio profitability impacts of the purported ‘withholding’ in order to determine whether the action could plausibly be connected to the exertion of market power. Additionally, the IMM should request information from market sellers in cases where the IMM suspects exercise of market power to consider whether there were other factors that explain the market sellers’ decisions,” PJM wrote.

PJM said the Monitor had not included an additional sensitivity the RTO had required be included in the report: the cumulative impact four recommendations the Monitor had made in its report on the 2024/25 BRA would have had if implemented in the 2025/26 auction. Those recommendations were establishing a sharper variable resource rate (VRR) curve, extending the must-offer requirement to intermittent resources, and excluding capacity offers from demand response (DR) and external resources.

Excluding DR from the auction would have reduced the excess unforced capacity (UCAP) by 8,769 MW, while doing so for external generation would have removed an additional 1,410 MW of excess UCAP. Combining the two would have left the RTO 6,983 MW short of the reliability requirement, pushing the clearing price to the $375.91/MW-day cap and resulting in a total capacity cost 42% higher than the actual results.

PJM said that gap would not have been made up for by other recommendations the Monitor made to increase available supply, such as requiring intermittent and storage resources to offer. That would have added 2,800 MW of available capacity, leaving a shortfall of 4,183 MW.

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Stakeholders Divided on PJM Proposal to Expedite High-capacity Generation

Stakeholders reacted sharply to additional detail presented on PJM’s straw proposal to create a one-off expedited application window for high-capacity-factor generation interconnection requests. (See PJM Proposes Expedited Interconnection Studies for High-capacity Factor Generation.) 

The proposal would allow a limited number of projects to be added to the initial clusters of Transitional Cycle 2 (TC2) to meet growing resource adequacy concerns staff have identified in the 2029/30 delivery year. The cycle currently includes only projects submitted between October 2020 and September 2021. More details on PJM’s proposal will be presented at the Oct. 30 Markets and Reliability Committee meeting. (See “PJM Models Suggest Capacity Shortfall Possible in 2029/30 Delivery Year,” PJM PC/TEAC Briefs: Aug. 6, 2024.) 

These approaches to determining eligibility were presented: allowing only projects with an effective load carrying capability (ELCC) class rating of 45% or higher or a formula with weighted factors such as ELCC rating; whether a project is an uprate or greenfield; expected commercial operation date; MW output and permitting required. 

The options would limit the number of projects being expedited to 100, which Director of Interconnection Planning Donnie Bielak said is the approximate number of projects staff believe can be analyzed without significant disruption to the milestones of other projects in the queue. If more than 100 projects are submitted, PJM would prioritize them on the amount of accredited capacity they could deliver. 

The 45% ELCC rating approach would categorically prohibit the participation of onshore wind, intermittent hydroelectric, and fixed and tracking solar, as well as projects being built as part of a state agreement approach (SAA) project. The in-service date would need to be June 1, 2029, or earlier. 

Speaking during the Organization of PJM States Inc. (OPSI) annual meeting Oct. 21, Ohio Lt. Gov. Jon Husted (R) said state leaders had met with PJM and requested the RTO create an expedited process for interconnecting resources that could be available any time of day. 

“Thank you and let’s go, that’s how we feel about it. We appreciate PJM’s responsiveness to our request,” Husted said. 

Speaking at OPSI, PJM’s Executive Vice President of Market Services and Strategy Stu Bresler said the initiative is meant to ensure that capacity market price signals can be acted on by generation developers. He said there are investors who want to act on high price signals sent in the 2025/26 Base Residual Auction but can’t do so while PJM progresses through its transitional approach to studying interconnection requests. 

PJM CEO Manu Asthana echoed that sentiment, saying load growth is accelerating at the same time generation deactivations are outpacing new entry. The Reliability Resource Initiative (RRI) would allow resources to respond to market signals quickly enough to address reliability concerns. 

“I think it’s important to create an onramp for additional resources that want to participate and provide that reliability,” he said. 

Several stakeholders at the Oct. 18 PC meeting said the proposal would amount to queue jumping, allowing preferred categories of generation to skip a line of mostly renewable resources that has spanned years. 

The projected reliability gap also was called into question, with stakeholders arguing that the markets are functioning to procure sufficient capacity and ancillary services. More data was requested around load forecasting and operational needs PJM expects. 

E-Cubed Policy Associates President Paul Sotkiewicz said PJM has not articulated a need to disrupt the rules generation owners have relied on to bring their units to those markets. 

“There’s nothing, absolutely nothing that tells me that we have to move quickly at this point,” he said. 

PJM Senior Director of Market Design and Economics Becky Caroll said the RTO’s Energy Transition in a series of PJM reports have documented the resource adequacy needs and the reliability services that intermittent resources in the interconnection queue are not expected to provide. 

On the other hand, stakeholders said it could create a pathway for adding storage to existing resources or unlock potential for existing generation to make upgrades to increase total capacity. 

Bielak said the proposal is one of three avenues PJM is investigating for addressing its reliability concerns, pointing to rule changes on capacity interconnection rights (CIRs) transfers to allow deactivating generation to be more easily replaced with new resources. The Planning Committee endorsed one of three proposals during its Oct. 8 meeting. (See PJM Stakeholders Endorse Coalition Proposal on CIR Transfers.) 

PJM also is open to re-evaluating its surplus interconnection service (SIS) rules, which allow new resources to be co-located with existing generation so long as there are no material adverse impacts and the combined output does not exceed the original resource’s CIRs. 

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PSEG Announces Route for Piedmont Reliability Project Tx Line

PSEG has announced its proposed route for the Maryland Piedmont Reliability Project (MPRP), a core component of the $5 billion in grid reinforcements the PJM Board of Managers approved in December 2022. (See PJM Board Approves $5 Billion Transmission Expansion.)

The 70-mile, 500-kV line would run from an existing right of way in northern Baltimore County, Md., passing through Carroll County to the Doubs 500-kV substation in Frederick County. The line is expected to cost $424 million to build with an in-service date in June 2027.

The utility said the line would address reliability needs prompted by generator deactivations and support energy affordability.

“Due to significant generation retirements that have occurred in recent years without replacement resources, the energy deficit in Maryland is projected to grow unless additional infrastructure like the MPRP is built,” the PSEG announcement said. “The additional import capability supported by the construction of the MPRP will help Maryland avoid growing their energy deficit, and thereby easing grid congestion and preventing grid overload, which can also benefit both energy affordability and reliability in the state. More transmission is needed to keep energy costs competitive and reduce the risk of rolling blackouts.”

The project was approved as part of the third window of PJM’s Regional Transmission Expansion Plan (RTEP), which sought to address needs presented by rising data center load growth and generation deactivations. That load growth has continued to accelerate, prompting PJM to open a window to create additional transfer capability into the northern Virginia region through the first window of the 2024 RTEP.

While the MPRP would source energy from the east on 500-kV lines, many of the proposals PJM is considering would run 765-kV lines from the west. (See “2024 RTEP Window 1 Projects Include Expansion of 765-kV Network,” PJM PC/TEAC Briefs: Oct. 8, 2024.)

Maryland and Virginia residents have spoken out against projects in both RTEP windows during PJM Transmission Expansion Advisory Committee meetings, arguing that the projects would disrupt historic and environmentally sensitive regions and burden residents already living along major transmission corridors. Three public hearings — one for each county — are being hosted by PSEG between Nov. 12-14, where information will be presented and feedback solicited.

“Over the last four months, PSEG’s team has analyzed over 5,300 public comments and arrived at a transmission solution. The proposed solution is community-informed, reliable and mitigates impact to individuals, communities and wildlife as much as possible while delivering a cost-effective solution for Maryland and PJM electric customers,” Project Director Jason Kalwa said. “We are committed to transparency and community engagement as a part of this process and encourage all interested residents to attend our upcoming public information sessions so that we can hear their comments and concerns.”

A webpage created for the project states that one of the most common sentiments in the public comments requests that the right of way parallel existing transmission lines in the region. But PSEG stated that a new right of way was preferable to avoid impacts to homes and schools along the existing corridor.

“Due to the built environment that has developed along the ROW over the past 50+ years, MPRP does not recommend this route due to impacts on residents, including direct impacts to more than 90 homes that parallel the right of way, and the community, including at least two places of worship and a school,” the page says.

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US Utilities Face Scramble to Meet New Demand

U.S. electric utilities have been caught “flat-footed” by the impending demand for electricity, Wood Mackenzie asserts in a new report. 

Growth of the U.S. economy has far outpaced growth in the amount of power needed to run the economy so far this century, but that trend is set to reverse, the analytics firm said in the October edition of its Horizons report. 

The expected growth of new electric-intensive technology in data centers, vehicles and industry sets the stage for constraints as the “move fast and break things” ethos of Big Tech bumps up against the five- to 10-year window in which generation and transmission projects are planned and executed. 

The utilities and developers that can adapt most quickly will reap rewards, according to “Gridlock: the demand dilemma facing the US power industry.” 

It adds that an era of upward pressure on wholesale power prices likely is at hand. 

Author Chris Seiple, Wood Mackenzie’s vice chairman of power and renewables, said in a news release that there will be a period of adjustment. 

“Most state public utility commissioners have little experience … regulating in a growth environment,” he said. “And as technology C-suites realize that energy may be the largest constraint on their growth, they are shocked as businesses that move at light speed learn about the pace at which electric utilities move.” 

Growth of U.S. GDP and U.S. electrical demand roughly tracked one another from the 1950s to the 1990s, and then electric demand tapered off, the report notes. In the 2010s, it said, electric demand was flat while the economy grew 24%. 

That is changing in the 2020s. 

The report forecasts demand growth of 4 to 15% through 2029, depending on region, with some utilities seeing a much greater increase. It suggests an integrated response from utilities, regulators and policymakers to meet this challenge. 

Projected sources of new demand through the end of this decade vary by ISO region. | Wood Mackenzie

The last time the U.S. electrical industry saw such unexpected demand growth was during World War II, Seiple said. Manufacturing output tripled from 1939 to 1944, and electricity demand rose 60%. 

“It was a closely coordinated national effort that brought together industry and policymakers to address the challenge and find innovation along the way,” he said. “A similar effort is needed now.” 

Wood Mackenzie identified data centers and artificial intelligence as a main driver of the increased demand — it said new data center announcements since January 2023 total 51 GW of new capacity.  

Not all will be built, the report notes, but neither is the list complete or comprehensive — there probably are more proposals that Wood Mackenzie did not identify. Oncor alone recently reported 59 GW of data center connection requests. 

The report bases its projections for future data center demand on 15% annual growth from 2025 to 2029, a midrange scenario. 

Meanwhile, a resurgent U.S. manufacturing sector, particularly for products such as batteries, solar wafers and computer chips, could add as much as 15 GW of high-load-factor demand. Electrolyzers for hydrogen production and chargers for EVs could add 7 GW. 

Against this backdrop, coal-burning plants are scheduled to retire in significant number, transformers and breakers are in short supply, and the interconnection process for new generation is sluggish. 

Outside the Northeast, planned retirement of coal generation facilities could place further strain on the supply of electricity. | Wood Mackenzie

This last factor — transmission planning, permitting and construction — is the biggest bottleneck, the report said. 

Seiple said an interesting dynamic to watch would be the number of coal plant retirements deferred and shuttered nuclear plants proposed for reopening in markets where there is no retail choice, compared to the number in markets where there is choice. More natural gas-fired generation is likely to be proposed, as well. 

The report cautions that projections of future growth in electric demand are fraught with uncertainty — it may not materialize as forecast if utilities cannot respond quickly enough. 

Secondary factors further muddy the picture: 

Many of the new factories being proposed would rely on government policies and/or subsidies that could change or be canceled. 

Developers of data centers want 24-7 clean energy at a steady rate to boost their environmental credibility, but most clean energy coming online today is intermittent. Nuclear fission may provide a solution, but not until the 2030s at the earliest. 

Emissions-free generation often is sited far from these new centers of demand, creating a need for new transmission and adding another layer of cost and complication. 

The report notes that developers, regulators and utilities have been looking for innovative solutions — or in some cases, an end run around each other, such as behind-the-meter generation co-located with demand. 

The report offers a suggestion to the electric utility sector: 

“Over the past 30 years, the industry has evolved the process of large-generation interconnection. It now needs to do the same for large loads to protect the financial interests of utility shareholders and ratepayers, to provide a transparent, non-discriminatory process for large loads competing for access to energy and to provide transparency to market participants on possible demand growth.” 

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New England States Seeking Increase of North-South Tx Capacity

The New England states are planning to solicit project proposals to increase the region’s north-to-south transmission capacity, the New England States Committee on Electricity (NESCOE) wrote in a letter to ISO-NE on Oct. 16.

The solicitations would be conducted through ISO-NE’s recently approved longer-term transmission planning (LTTP) process, which sets a framework and default cost-allocation method for transmission procurements to meet long-term needs. Project costs would be regionalized by load unless the states agree to an alternative cost allocation methodology. (See FERC Approves New Pathway for New England Transmission Projects.)

“NESCOE is interested in focusing the first LTTP solicitation on increasing transfer capability within the system to allow more power to flow from Maine to New Hampshire and into southern New England,” the group wrote.

The need for increased north-to-south transfer capability was one of the key high-likelihood concerns identified in ISO-NE’s 2050 Transmission Study, which projected overloads along the Maine-New Hampshire and North-South interfaces starting in 2035.

While the study showed overloads in both summer and winter, the most significant overloads occurred in the winter amid periods of high output from offshore wind resources interconnecting in Maine and New Hampshire. Connecting offshore wind resources from the Gulf of Maine to the grid in Massachusetts, instead of in northern New England, could help alleviate this stress on the grid. (See ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points.)

Although offshore wind will require major transmission investments wherever it interconnects, the first LTTP solicitation appears focused on onshore renewables. NESCOE wrote that one of the key objectives of the solicitation will be to facilitate “the integration and deliverability of additional affordable generation resources located in northern Maine.”

“Recent studies, along with the current interconnection queue, indicate that on the order of 3,000 MW of additional generation capacity could potentially be developed in northern Maine. NESCOE is interested in solutions that would facilitate the integration of these resources,” the group added.

Renewable power advocates in New England have long sought to unlock the potential of renewables — onshore wind in particular — in northern Maine, but this part of the region is not directly connected to the ISO-NE grid.

In 2022, Maine selected a proposal from LS Power for a 345 kV line to connect the area to the region’s grid, but the Maine Public Utilities Commission canceled the procurement after the projects’ projected costs increased. The PUC plans separate solicitations for transmission and generation in the area, and a proposal from Avangrid recently received financial backing from the federal government. (See Long Road Still Ahead for Aroostook Transmission Project.)

Alex Lawton of Advanced Energy United expressed his excitement about NESCOE’s announcement and said it is “amazing to see our region being proactive and leading the way on transmission planning.”

He added that northern Maine has “some of the cheapest, most abundant renewable potential” in New England, and unlocking more north-south transmission capacity is “one of the more low-hanging fruit and promising areas for cost-effective transmission in New England.”

Next Steps

NESCOE said it is seeking stakeholder feedback on how best to achieve its goals of increasing north-south transmission capacity and integrating renewables in northern Maine, as well as “any other feedback that may increase the likelihood of a successful solicitation.”

The organization said it is considering a requirement for proposed solutions to “increase the Maine-New Hampshire interface capacity to at least 3,000 MW by 2035 and increase the Surowiec-South interface capacity to at least 3,200 MW by 2035.”

The capacity of the Maine-New Hampshire interface is 2,000 MW, while the more northern Surowiec-South interface has a transfer limit of 1,800 MW.

NESCOE wrote it also is “weighing the tradeoffs of including a requirement for solutions that extend farther north into Maine.”

“While such a requirement would further facilitate the transfer of cost-effective power across these interfaces, NESCOE seeks to avoid an overly prescriptive scope that may hinder the success of a potential [request for proposals] by unduly limiting the pool of bids or by reducing the likelihood of soliciting a cost-effective solution,” the group wrote.

NESCOE will discuss the preliminary scope of the solicitation with stakeholders at the ISO-NE Planning Advisory Committee meeting on Oct. 23, which will be open to the public.

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Regulators Get Look into Monitoring Plans for Markets+

Western regulators on the Markets+ State Committee (MSC) on Oct. 18 probed an SPP Market Monitoring Unit (MMU) official on how the division plans to address the implementation of the new day-ahead market.  

Jodi Woods, SPP director of market monitoring, gave the MSC an overview of the mission and scope of market monitor functions, reiterating that SPP’s monitor is internal to the RTO, functions independently and investigates problems and appeals to FERC, but cannot force a position or set a penalty.  

With the implementation of Markets+, the MMU will engage consistently with the MSC and continue regular functions such as monthly, quarterly and annual reporting.  

New Mexico Commissioner Gabriel Aguilera asked whether the MMU would increase staffing levels to account for Markets+. Woods responded that an increase is accounted for in the budget and that the MMU will likely have a separate set of employees tackle Markets+ issues. 

Arizona Commissioner Nick Myers, who chairs the MSC, asked if there would be staff overlap.  

“There was actually a preference from the Markets+ participants that there not be a lot of overlap and that there [be] assurance that the headcount that Markets+ is paying for, which is completely understandable, is actually working on Markets+ issues,” Woods said. “The construct we’ve proposed would allow for a separate Markets+ team that would be focused primarily just on Markets+ issues.”  

The MMU has budgeted for around 14 additional employees to be added to the team.  

Aguilera additionally asked about the MMU’s process for opposing a tariff change and whether the monitor has its own attorneys.  

“If we do decide to file comments in the docket, once the revisions have been filed, we do have external counsel. Sometimes we do it ourselves … but we don’t have lawyers on our team,” Woods said.  

Aguilera emphasized the value of having an independent group monitoring activity in the new market.  

“It is really essential when we have these incredibly complex machines that are markets and very sophisticated participants who could potentially take advantage of those complex rules,” he said. “I think that the work you do is just invaluable.”