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July 2, 2024

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How Sea Level Rise, Coastal Flooding Threaten Boston’s Grid

For much of its early history, Boston was a city expanding into the sea.  

A hilly peninsula prior to colonization, the city began the labor-intensive process of removing its hilltops to fill in the surrounding coves, marshes and mud flats at the end of the 18th century.  

The summit of Beacon Hill, adjacent to the Massachusetts State House, was carted off in the early 1800s, while Mount Vernon and Pemberton Hill, which formed the peninsula’s “Trimountain” landmark alongside Beacon Hill, fared even worse. In the words of Boston historian Walter Muir Whitehill, “the hills have all but disappeared.”

Today, more than half the city is built on a landfill foundation of former hilltops and assorted city waste. As a result, a major portion of Boston’s streets, bars, apartments and power infrastructure are located just above historical flood lines.

Boston topography 1630 to present | The Boston Public Library

The outward expansion has enabled Boston to become the city it is today but also has made it especially vulnerable to the rising tides that threaten to force the city into retreat.  

By 2100, the sea level around Boston is projected to rise by two to five feet, according to a 2022 report by the University of Massachusetts Boston.

The report projected precipitation intensity to increase by 20 to 30%, while sea level rise likely will push up groundwater levels and increase groundwater salinity along the coast. If emissions continue at current rates, 100-year flooding events could become annual occurrences by the end of the century. 

“Risk-averse end users of these projections should consider the possibility of sea level outcomes above the likely range, especially under higher GHG emissions,” the UMass report noted. “For long-term planning and long-lived coastal assets, we stress that sea level will continue rising beyond 2100 under all GHG emissions scenarios.” 

Rising Costs of Resiliency, Recovery

In Boston and throughout the broader region, climate-fueled extreme weather events already are stressing essential energy infrastructure. 

“We see a lot of concern about the ability of the grid to withstand even current — not to mention future — storms, sea level rise and other climate impacts,” said John Walkey, director of climate justice and waterfront initiatives at the environmental justice nonprofit GreenRoots.  

As climate change accelerates, “all our past planning and forecasts go out the window,” Walkey said.  

Massachusetts’ electric utilities have incurred major costs associated with storm recovery in recent years. Eversource, one of the state’s two major electric distribution companies, is seeking to recover about $339 million in costs associated with three storms that occurred between 2021 and 2022, including $176 million from a single 2021 Nor’easter (D.P.U. 22-143). 

Over the past decade, Eversource’s contributions to its storm fund, which is intended to stabilize the impacts of storm costs on ratepayers, have increased from about $5 million to $31 million annually (D.P.U. 22-22).  

In the fall of 2021, Eversource reported its storm fund had a $122 million deficit, which the company attributed in part to increasingly frequent storms “due to weather patterns and meteorological characteristics associated with climate change.” 

In a recent interview, Massachusetts Department of Public Utilities Chair Jamie Van Nostrand emphasized it’s the utilities’ responsibility to prepare their systems for increasing pressures from climate change. 

With more frequent and severe extreme weather events and increasing property values, elevated storm costs are “not necessarily a matter of the utilities being imprudent,” Van Nostrand told RTO Insider. “But we’ll also be looking closely at, ‘Could that have been avoided? Could you have designed your system in a way that would have been more resilient?’” 

In 2022, Massachusetts passed a bill requiring the state’s electric utilities to file electric-sector modernization plans (ESMPs) with the DPU every five years. The bill requires the utilities to detail how they plan to upgrade their systems to facilitate the clean energy transition and mitigate climate damage. (See Mass. Utilities Submit Grid Modernization Drafts.) 

The utilities filed their final plans in January, which the DPU should rule on in late August, Van Nostrand said. 

“Even without that specific statutory directive, I think that part of our job is to put the utilities on notice that we’re watching, and we want you to take [climate resilience] into account,” Van Nostrand said, adding that utilities will “run the risk of a prudence disallowance” if they incur costs that could have reasonably been avoided by proactive climate mitigation.” 

The utilities’ ESMPs outline major investments to meet increasing peak loads and enable the transition to more distributed generation. Eversource estimates it will need to build 17 new substations and upgrade 26 substations by 2035.  

“It’s very timely that we’re looking at the climate change resilience piece,” Van Nostrand said, “because we’re going to be installing a lot of substations, upgrading a lot of substations, and we want to make sure the utilities are mindful as they’re making all these investments.” 

While storm costs are often driven by downed trees and branches, large flooding events can pose a significant threat to substations. 

National Grid, Massachusetts’ other major electric utility, noted in its ESMP filing that flooding in its Rhode Island service territory in 2010 forced the company to remove eight substations from service and caused “significant customer outages and loss of high-value substation equipment.” 

The company wrote that it used Federal Emergency Management Agency (FEMA) flood maps to analyze its substation fleet in the aftermath of the events to identify vulnerabilities. 

“Flood mitigation efforts have been implemented at approximately 40 substation locations with approximately 20 additional projects planned,” National Grid wrote. 

Elli Ntakou, Eversource’s manager of system reliability and resiliency planning, said the utility assesses risk based on FEMA flood data and sea level rise projections from the City of Boston and the National Oceanic and Atmospheric Administration. 

“Especially for sea level rise, we want to be comprehensive,” Ntakou said.  

Elevation in East Boston

Sea level rise resiliency has been one point of contention in the lengthy fight over Eversource’s proposed substation on the banks of Chelsea Creek in East Boston, which has led to demonstrations and arrests of protesters attempting to stop construction.  

Environmental justice organizations and residents have argued Eversource failed to conduct adequate community engagement on the project and have expressed concern that future climate-driven flooding could inundate the substation, endangering the surrounding neighborhood.

GreenRoots and the Conservation Law foundation have a pending legal challenge before the Massachusetts Supreme Judicial Court regarding the Energy Facilities Siting Board’s (EFSB’s) approval of the project (EFSB 14-04A).  

“We don’t feel as if they really prepared for the lifespan of this facility, [or] they prepared for the lifespan of a transformer,” said Walkey of GreenRoots, adding that substations can last for more than a century.   

Eversource considered sea level rise over a 40-year equipment lifespan and selected a design flood elevation — “the lowest elevation at which the Substation equipment should sit on the site” — of four feet above the 500-year flood line.  

Eversource said the substation “was approved following a comprehensive, yearslong public review process” and that the company “comprehensively demonstrated that the project is designed to mitigate flood risks well beyond any flood study for the project.” 

The EFSB ruled Eversource “appropriately addressed risks associated with sea level rise” and added that “building the substation at a higher elevation would likely add costs to project development and provide unclear benefits.”  

Future Uncertainty

One major challenge of planning for coastal flooding is the high level of uncertainty associated with projecting future emissions, as well as how largescale earth systems will react to different warming scenarios. 

While Boston is likely to experience sea level rise of two to five feet, “that’s really all we can say, because it depends on the emissions of greenhouse gases,” said Paul Kirshen, professor of climate adaptation at UMass Boston and a lead author of the UMass climate impacts report.  

“If we can get to net zero by 2050, it could only be two feet. If we keep on the rate we’re going, it could be five feet,” Kirshen said.  

Projection of a hundred-year flood with three feet of sea level rise | City of Boston

He added there is an “outside chance” that sea level rise could reach up to 10 feet by the end of the decade, depending on the degree of melting on ice sheets in Greenland and Antarctica. 

“It’s a low probability,” Kirshen said, “but that would obviously be a real game changer.” 

Climate change also could increase the potential for low-probability, high-consequence compound flooding events in which river flooding coincides with a storm surge, Kirshen said.  

“We’re at the confluence of three rivers — the Mystic, the Charles and the Neponset River — and there’s always the possibility of those rivers being flooded from precipitation at the time that we get a major coastal storm,” Kirshen said. “Not only would you get flooding from the ocean from the storm surge, but you’d also get the Charles River and the Mystic River overflowing their banks.” 

To help account for the changing climate risk profiles, in recent years the DPU has mandated that newly sited projects reassess their climate vulnerability every five years and take any additional necessary mitigation measures. 

“It just makes sense if you’re installing energy infrastructure that’s going to have a lifespan of 30, 40, 50 years,” said DPU Chair Van Nostrand. “We’re always getting more information, and if anything, I think the information we’ve gotten is a little bit scarier. … Sea level rise might be even worse than we were thinking.” 

Some environmental organizations and legislators are looking to require even more comprehensive climate resilience planning from the utilities. One bill reported favorably out of the legislature’s Telecommunications, Utilities and Energy Committee would require the state’s investor-owned utilities to submit a climate vulnerability assessment and adaptation plan every five years. 

Johanna Epke, staff attorney at the Conservation Law Foundation, said current requirements have provided limited visibility into how the utilities are planning for climate impacts.  

“They’re not required to file any of their modeling or any of their assessments,” Epke said. “We want that out in the public space, we want to be able to scrutinize that, and we want to have experts in the advocacy community comment on that.” 

Van Nostrand said he thinks the DPU already has the statutory authority to require climate vulnerability assessments as part of the ESMP process.  

“As a result of the 2022 climate law, we will be making specific findings on climate vulnerability assessments when we issue the August order on this first round of ESMPs,” Van Nostrand said. “Apart from that, we can also rely on our broad regulatory oversight powers to be able to say, ‘We think that it’s part of utility practice that you perform this kind of a study and manage your system in a way that manages risks.’”  

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ASE: Energy Transition Must Put Demand-side Efficiency, Flexibility First

WASHINGTON ― Gene Rodrigues, who heads the U.S. Department of Energy’s Office of Electricity, managed to get through a thundering, seven-minute keynote at the Alliance to Save Energy’s Policy Summit on May 8 without even one de-rigueur mention of the Inflation Reduction Act, Infrastructure Investment and Jobs Act or President Joe Biden’s economic agenda.  

Rather, he came to the summit to deliver a ringing endorsement of ASE’s new campaign to convince the energy industry, state regulators and Capitol Hill lawmakers that “demand is the new supply.”   

In the past, the energy industry “looked at everything from one end of the microscope,” said Rodrigues, who spent a large chunk of his 23 years at Southern California Edison working on demand-side initiatives. “If you need more reliability, if something goes down and you just need more power, if you need to ensure that everyone has access to the benefits of energy, then you … just build more. We need more, bigger plants. We need more transmission corridors. We need, we need, we need. That is the most inefficient way to think about solving the problem.” 

Creating a net-zero economy ― with electrified buildings, transportation and industry ― will mean major increases in energy demand, so using a full array of demand management strategies and technologies will be not only critical, but “obvious,” he said. “It is a basic concept of efficiency, of ensuring that the steps we take are economic, impactful and they reach every single American no matter where he or she resides … It is an expression of common sense.” 

ASE CEO Paula Glover similarly framed the combination of aggressive efficiency and demand management as “the backbone of any energy transition that we aspire to have that is going to be equitable, reliable, resilient and affordable.” 

Demand is the new supply means “transforming energy demand into … dynamic, responsive supply. [It] is necessary and has to start now,” Glover said in her opening remarks at the summit. “This approach is crucial for stabilizing our grids and distributing energy more equitably across communities.” 

Conference panels and speakers presented different approaches to growing demand management as supply, from the consumer and regulatory paradigm shifts needed to scale virtual power plants to new research from Lawrence Berkeley National Laboratory (LBNL) showing the impact of efficiency on regional load curves.  

Electrification without aggressive efficiency could result in summer peak demand not only increasing, but shifting to later in the evening, said Andrew Satchwell, deputy leader in LBNL’s Energy Markets and Policy Department. Produced in partnership with The Brattle Group, the study also found roughly half the regions studied could see a shift from summer to winter peaking due to the inefficiency of “a lot of electric resistance building heating,” Satchwell said. 

But the study also showed that a combination of aggressive demand- and supply-side measures could slash greenhouse gas emissions in the building sector to 91% below 2005 levels by 2050 without any major increase in building electricity use. Further, leveraging building efficiency and flexibility could provide $100 billion in power system savings per year by 2050, which could offset more than a third of the costs of grid decarbonization.  

“We see a strong potential for energy efficiency to reduce emissions in the near term, while the grid is still decarbonizing, that then enables later reductions from … electrification under a harmonized grid,” said Aven Satre Meloy, a computational research scientist and engineer at the Berkeley Lab.  

Calling the study a “clear-eyed view of the economic case” for demand-side measures, Rodrigues ended his keynote with a call for industry stakeholders to “work on both ends of the scale to balance the grid. Demand is the new supply does not push anything off the table,” he said. “For those who believe in all-of-the-above, it’s just a way to work smart; work smarter, not harder.” 

The LBNL-Brattle study found that by combining electrification with aggressive efficiency, the U.S. could reduce CO2 emissions from the building sector 91% below 2005 levels by 2050. | Lawrence Berkeley National Laboratory

Start Right Now

While utility executives frequently say that the least expensive kilowatt-hour is the one you don’t use, demand-side initiatives in general have not had a strong profile in the energy transition.  

In its 2023 Utility Scorecard, the American Council for an Energy Efficient Economy found that the nation’s 53 largest utilities had decreased their spending on efficiency by 4.9% in the five years since ACEEE’s last utility rankings. That cut in spending resulted in a 5.4% decrease in energy savings and a 19% drop in peak demand reductions. On average, the ranked utilities spent 2.2% of their revenue on energy efficiency. 

According to a January 2024 tally from the International Code Council, 13 states have adopted the latest, 2021 International Energy Conservation Code for residential buildings, while only 11 have adopted IECC 2021 for commercial buildings. Two more, Maine and Massachusetts, have adopted the 2021 updates as “stretch” codes.  

IECC codes are updated every three years. Six states still are using the 2009 code.  

The LBNL-Brattle study finds an aggressive approach to efficiency and demand flexibility will be vital for the U.S. to have any chance of hitting Biden’s goal of cutting economywide GHG emissions to net zero by 2050 without major increases in demand and grid impacts. 

The scale of such efforts could be daunting. The building sector accounts for 35% of U.S. carbon dioxide emissions and 74% of electricity sales, according to LBNL. The study looks at a range of scenarios tracking the effects of cutting emissions and electricity consumption through various combinations of electrification and low, moderate and aggressive energy efficiency and demand management.  

LBNL’s most aggressive scenario would require 98 million to 141 million fossil fuel or electric-resistance water heaters to be replaced with heat pump water heaters by 2050, as well as high-efficiency retrofits for building envelopes on 109 million existing homes and up to 43 billion square feet of commercial space. Advanced HVAC controls also would be needed for more than 75% of homes and 50% of commercial buildings. 

And, Satre Meloy said, “It needs to start happening right now in order to achieve that very dramatic or very favorable building-centric future in 2050.” 

Electrification with no or low efficiency would cut CO2 emissions but almost certainly would result in increased electricity demand, the study finds. The effects of moderate and aggressive efficiency are more variable; emissions would go down, but electricity use could rise or fall, depending on a range of factors.  

One example, the study’s aggressive efficiency scenario factors in “breakthrough” technologies ― such as super-efficient building envelopes and energy management systems ― are in the research and development phase but expected to reach commercial scale and price points by 2030 or 2035. 

Increasingly rigorous building efficiency codes and standards also will be needed, Satre Meloy said. “Failing to do these things is substantially reducing the total avoided emissions” by 40% to 58%, he said.  

The effects on the grid also could be substantial, with “inefficient electrification” leading to increased peak and shifting demand patterns, Satchwell said. In Texas for example, the study found that efficient electrification could drive the state’s summer peak below a business-as-usual level. For a winter-peaking system in the Northwest, efficiency could cut in half any increase due to electrification.  

Efficiency and flexibility mitigate electrification load increases in both summer- and winter-peaking systems. | Lawrence Berkeley National Laboratory

Shifting the Paradigm

So, what it will take to get building efficiency and demand flexibility technologies ― like virtual power plants ― to commercial scale and well-integrated into distribution systems? The discussion during a panel on scaling VPPs centered more on paradigm and regulatory shifts than the technologies themselves. 

For Jessica Granderson, director of LBNL’s Building Technology and Urban Systems Division, buildings are an “underexploited resource” and the “central hub in the transfer of clean electrons in our energy transition to and from that clean grid.” 

“Our buildings have built-in storage already, right in the mass of the building, in the fabric of infrastructure, in the chilled and hot water that we’re using to serve those loads,” Granderson said. “We have the technologies, the communications and the standards now [that] we didn’t previously have to access that built-in storage and exercise it dynamically.” 

Mary Sprayregen, global head of regulatory affairs and global market development at Opower, sees a major misalignment between projections of growing residential energy efficiency and demand management and the current reality that about 8% of households are enrolled in utility demand-response programs.  

“And that number has not changed over the last several years despite all the attention we are drawing to it,” Sprayregen said. “How do we engage these untapped resources in everyday houses in a way that everybody can participate, but … that is not necessarily controllable, and it’s not necessarily device-based, but it’s behavior-based?” 

Opower designs and runs such programs for utilities. 

Marisa Uchin, chief strategy and growth officer at Franklin Energy, called for a reimagining of the power system “because we have distributed resources on the supply side hidden on the demand side. We have the opportunity to create the VPPs or to create sources of power that are … on a different size and scale” and can be “distributed any place where potentially demand and supply chains are complex.” 

But technology changes at the residential level generally are driven by comfort, upfront cost and a crisis ― the breakdown of a major appliance ― Sprayregen said.

Granderson agreed but called for “changing that paradigm to something that is like where our decisions are system-optimal, and I think, we have to be really cognizant and intentional that that is the change we’re looking to drive. … So, we’re going to think about the ways we combine those solutions to reach everyone in different markets and contexts.” 

Another major hurdle for Sprayregen is designing appropriate incentives for utilities to accelerate deployment of efficiency and demand flexibility. Regulatory decision-making is rooted in an inherent conflict between “capital expenditures versus operational expenditures,” she said. “So, how do we get past that?” 

Sprayregen, Granderson and Uchin agreed artificial intelligence will be the next critical tool for optimizing the system impacts of energy efficiency and demand management.  

“When it comes to policymakers, specifically utility regulators, there has got to be a pathway where software solutions are on par with capital expenditures,” Sprayregen said. “We’ve got to level that playing field.” 

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Consumer Advocates, Environmentalists Urge Holistic Thinking at PJM

BALTIMORE — The Public Interest and Environmental Organization User Group (PIEOUG) discussed costly generation deactivations, RTO versus member filing rights over regional planning and long-term transmission projects with members of the PJM Board of Managers on May 8, the final day of the 2024 PJM Annual Meeting. 

Much of the discussion centered around transmission, how PJM can increase the amount of regional planning it conducts, the cost of utility-designed supplemental projects and a proposal to shift filing rights over the Regional Transmission Expansion Plan (RTEP) from the Members Committee to PJM’s board. (See Members Vote Against Granting PJM Filing Rights over Planning.) 

Ari Peskoe, director of the Electricity Law Initiative at Harvard University, argued that proposed revisions to the Consolidated Transmission Owners Agreement (CTOA) to grant PJM sole filing rights over the RTEP under Federal Power Action Section 205 include language that would allow TOs to supplant PJM-initiated projects with more expensive plans introduced by utilities and would create a “shadow governance” where CTOA signatories could challenge PJM prospective Section 205 filings, PJM regional plans, or other PJM actions through a confidential mediation process. 

Peskoe argued the CTOA revisions to allow utilities to declare their intention to build a similar project as one in the RTEP could interact with existing tariff language prohibiting PJM from “planning a duplicative project” to force PJM to remove components from its plan without consideration of the merits of each proposal or whether they are likely to be built. Following the PIEOUG meeting, he submitted a letter to the board recounting his comments. 

“The CTOA creates new veto powers and broad rights of first refusal, as well as new opportunities for each utility to interfere with regional planning, PJM’s FERC filings and other PJM actions. The new CTOA also subjugates PJM’s RTO status to the CTOA, reduces transparency for PJM members and states, and limits PJM’s options as it navigates the energy transition. It would create a new shadow governance system where utilities will have the advantages,” he said in the letter. 

The MC overwhelmingly rejected corresponding revisions to the PJM Operating Agreement and tariff to transfer filing rights May 6, which several members argued were being rushed through the stakeholder process and could lead to PJM being able to make unilateral economic determinations about the viability of generators. The transfer would require revisions to both the CTOA through the agreement of the Transmission Owners Agreement-Administrative Committee (TOA-AC) and the PJM board, as well as the amendment of the OA and tariff. The board notified stakeholders May 10 it’s deferring deciding on the CTOA revisions until after the FERC filing on long-term transmission planning, noting the MC’s rejection of the changes. 

Attorneys representing transmission owners supporting the CTOA revisions responded to Peskoe’s comments in a May 9 letter to the board, stating the changes would not empower TOs to remove PJM-selected projects from the RTEP in lieu of their own, but rather would allow them to continue to move forward with projects at the risk of FERC finding them imprudent. 

“Nothing prevents PJM from continuing with the RTEP project,” the letter states. “PJM is obligated to go ahead with the regional project. If any change occurs, it would be PJM revising its project to address the Transmission Owner project need, in which case the risk would be on the Transmission Owner to move forward with its project, as outlined above.” 

The TO letter also states the new mediation process is similar to those approved by the FERC in the past and would allow PJM or TOs to be party to a complaint to dispute the results at the commission. 

Consumer Advocates Call for More Holistic Thinking at PJM

Brian Lipman, of the New Jersey Division of Rate Counsel, said the number of stakeholder meetings and the pace at which consequential topics are discussed can make it difficult for consumer advocates to stay engaged. His concern about timing extends to the Base Residual Auction (BRA) schedule as well, which has been compressed from its usual three-year advance cycle to allow multiple market changes to be implemented. He said running auctions in close succession increases the odds of errors being introduced, as he said happened with the results of the 2024/25 BRA for the DPL South zone, where FERC ordered PJM to recalculate the results using parameters that caused a substantial increase in prices. (See related story, Following Court Ruling, FERC Reluctantly Reverses PJM Post-BRA Change.)

“It’s so important that we make sure that PJM is not making mistakes … the timing, the rushing makes us nervous,” he said. 

Lipman said the advocates’ outside position in the market and planning processes make it difficult for them to receive and analyze data about the drivers behind costs faced by consumers. Generation and transmission owners hold data about their assets and operations that can be difficult for advocates to request, even when it is shared with PJM. 

Board Member Vickie VanZandt said determining the most reasonable cost requires breaking down silos and holistic solutions, but that transmission owners are best placed to understand the condition of their infrastructure. She questioned how the advocates view where supplemental projects fit into risk management. 

Lipman responded that TOs look only at their own assets, whereas PJM can consider regional solutions that could meet the needs of multiple supplemental projects at a lower cost. However, it does not factor local transmission issues into its RTEP proposals. 

“We’re losing those opportunities, and frankly, they’re costing ratepayers a significant amount of money,” he said. 

Environmentalists Call for More Flexibility Around Deactivations

Casey Roberts, of the Sierra Club, said PJM’s lack of a proactive plan for replacing retiring resources is missing opportunities to improve the reliability and flexibility of the grid, speed the development of clean energy and save consumers money. She said deactivating generators tend to be older and have lower capacity factors that contribute to them receiving capacity market signals that they no longer are needed for resource adequacy. By holding onto those resources through RMR contracts to resolve transmission violations, she argued the reliability of the grid is dependent on resources that themselves are less reliable. (See PJM Rejects Storage as Alternative to Brandon Shores RMR.) 

Generators operating on RMR contracts also prevent the redeployment of transmission capability, slowing the pace of new generation coming online, including those that might resolve the same violations necessitating the RMR contract. 

She said a study conducted by Gridlab and Telos Energy looking at the feasibility of installing an 800-MW battery at the point of interconnection of the 1,295-MW Brandon Shores found that storage paired with transmission upgrades could resolve the violations at a lower cost than PJM’s solution. And it would replace a 40-year-old coal generator with a battery boasting a quick ramp rate and other parameters that thermal generators may lack. 

Introducing alternatives to operating generators on RMR contracts while lengthy transmission projects are completed would require a mechanism for CIRs to be transferred to new resources, a longer notification period for generation owners seeking to take units out of commission and TOs working grid-enhancing technologies (GETs), such as dynamic line ratings (DLRs), into their solutions.  

Katie Siegner, of RMI, said FERC has made clear that its Order 2023 on generator interconnection should be seen as a floor by RTOs and encouraged PJM to not simply comply with its requirements. She said incorporating GETs into the network upgrade studies performed by PJM and developers for new resources could speed the entry of renewable resources and save customers $1 billion annually by reducing transmission congestion and integrating lower-cost resources onto the system. (See RMI Report: GETs Could Speed Renewable Development, Save Consumers Billions.) 

Nick Lawton, of Earthjustice, said development of clean energy, deactivation of fossil generation and transmission planning are intricately linked, but are viewed through siloed stakeholder processes. He said about 5% of the energy produced in PJM is generated with renewable resources, while other regions are far ahead. 

“It’s hard for me not to conclude that PJM is behind,” he said, adding that means the RTO doesn’t need to reinvent the wheel because the success of others shows the path forward. 

Lawton also argued the backlog of proposed generation projects in the interconnection queue has contributed to the slow pace of new entry in PJM and urged staff to continue improving the cluster-based approach the RTO initiated this year. (See PJM Initiates Transitional Interconnection Queue.) 

“PJM can make the energy transition work but the pace of the transition depends on how quickly PJM acts,” he said. 

Board of Managers Chair Mark Takahashi said about 40 GW of generators have cleared the interconnection queue and have signed interconnection service agreements (ISAs). Most are renewables, but they haven’t yet moved to construction. 

Lawton responded that in many cases, the amount of time it took resources to receive an ISA affected their ability to hit the ground running once it arrived, particularly because of changing economic conditions. 

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PJM Members Committee Briefs: May 6, 2024

Stakeholders Re-elect 3 PJM Board Members Over Consumer Dissent

BALTIMORE — The Members Committee voted to re-elect three members of the PJM Board of Managers, placing Paula Conboy, David Mills and Vickie VanZandt on the board for additional three-year terms. 

Board member and Nominating Committee Chair Dean Oskvig said all three candidates are completing their first term on the board and “hit the ground running” in his experience working with them. Conboy and Mills were first elected to the board in 2021, while VanZandt was appointed to the board in September 2022, following the resignation of board member Sarah Rogers. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), told the MC that several advocates were voting against their re-elections to express frustration and waning confidence with the board’s handling of the clean energy transition, market power concerns and the lack of analysis on the cost impacts of transmission. 

PJM Board Member Dean Oskvig | © RTO Insider LLC

Poulos also stated there’s uncertainty around the functioning of the capacity market and a feeling that the board rushed stakeholders to a vote on proposed revisions to the Operating Agreement and tariff to transfer filing rights over regional planning from PJM’s membership to the board. 

The MC voted against that proposal May 6 and on May 13 the board issued a notification that it’s deferring action until after the May 13 FERC order on regional planning. (See Members Vote Against Granting PJM Filing Rights over Planning.) 

Because the board tends to speak as a single body, Poulos said it’s difficult to discern where individual board members stand on issues and the advocates’ “no” votes were not against any of the candidates as individuals, but rather to signify dissatisfaction with the direction the board has taken. 

Productive Year of Changes in 2023, Say Asthana and Midgley, Challenges Ahead

PJM CEO Manu Asthana opened the RTO’s 2024 Annual Meeting stating the organization has had an exceptionally strong year of reliability and is in the process of implementing market redesigns drafted throughout 2023 to poise PJM to continue performing well. 

Changes to the Reliability Pricing Model (RPM) created through last year’s Critical Issue Fast Path (CIFP) process calibrate market signals to the energy transition’s new realities, he said. The changes also move ahead on improving generation accreditation, adding sophistication to risk modeling and enhancing testing of generator’s capabilities, he added. (See FERC Approves 1st PJM Proposal out of CIFP.) 

Asthana said the January 2024 Winter Storm Gerri presented many of the same challenging conditions as the December 2022 Winter Storm Elliott, which pushed PJM into some of its most severe emergency procedures and was one of the contributing factors to launching the CIFP process. This time around, however, transmission and generation performance improved, and PJM’s load forecasting was accurate in the days ahead of the storm. (See PJM: ‘Conservative Operations’ Maintained Reliability During Jan. 2024 Storm.) 

“We learned from the experiences of Elliott, and we saw it come to fruition in Gerri,” he said. 

PJM also initiated the transition to a cluster-based approach to studying new generation interconnection requests in 2023, Asthana said, setting a goal of completing the fast-track queue this year. 

“We’re making a lot of process on generation interconnection, which I feel good about,” he said. 

The acceleration of the clean energy transition is catching the world flat-footed, and more work is needed at PJM, he said. Generation deactivations, new entries and the pace of load growth are surprising, particularly with the introduction of data centers, electric vehicle charging and hydrogen production load, Asthana said. The timing of the transition largely is out of PJM’s control and policy tradeoffs likely will be needed but he said discipline and effort in the stakeholder process can reveal solutions. 

“There is a lot of work that we still have to get right working together and time is not our friend,” he said. 

MC Chair Sharon Midgley, Exelon vice president of federal regulatory affairs, said the CIFP changes and a proposed regional planning paradigm will improve PJM’s ability to meet rapid load growth and changes in the generation mix. PJM’s proposed long-term regional transmission planning (LTRTP) process is being considered by the Markets and Reliability Committee, which deferred a vote April 25 to await the FERC regional planning order. (See “Stakeholders Defer Vote on Long-term Planning Proposal,” PJM MRC Briefs: April 25, 2024.) 

“I am cautiously optimistic that we will see some order of LTRTP implemented at PJM in the short term,” Midgley said. 

She also highlighted the proposal to transfer Federal Power Act Section 205 filing rights over the transmission planning protocol to PJM, stating PJM will need every tool at its disposal during the clean energy transition. PJM currently is the only RTO that does not have these rights over its planning rules.  

Stakeholder collaboration also will need to be centered in PJM’s efforts to navigate the transition, she said. “It is incumbent on everyone in the room to work together to ensure reliability through the energy transition.” 

PJM Panel Discusses Innovation and Technology

PJM held a panel on its efforts to use innovation to find solutions to the challenges posed by climate change, generation interconnection and control-room operations. The panel was moderated by Chief Communications Officer Susan Buehler and featured Chantal Hendrzak, executive director of IT operations and architecture; Dave Souder, executive director of system operations; and Emanuel Bernabeu, senior director of applied innovation and analytics. 

As more intermittent resources come onto the grid and weather becomes less predictable, Souder said forecasting needs to look not only at the storms’ magnitudes but also their precise timing to understand how weather may impact available generation, adding that even thermal resources can be affected by higher water and ambient air temperatures. He said PJM is looking at expanding its data science team to investigate factors such as the impact ice can have on wind turbines, wildfires interrupting solar output and high winds disrupting thermal generators. 

Machine learning can be employed in the control room to analyze past outages and the responses taken to determine which solutions may be best employed in real-time operations. During the June 2022 derecho that caused outages in Ohio, Bernabeu said technology could have reduced load shedding by about 20% and allowed grid operators to make critical decisions more quickly. 

Hendrzak said AI tends to be limited by its focus on learning from past experiences, but in the context of cybersecurity it can be used to develop a baseline pattern of normal user behavior to detect anomalous activity that could signify an intrusion. 

Bernabeu said one of the challenges in using machine learning to improve operations is the infrequency of major events on the grid, increasing the importance of interregional information sharing about outages. 

“It’s a terrible thing to waste a blackout so I always go and inspect everything about them,” he said. 

Hendrzak said she foresees a role for AI in the generation interconnection process to aid developers in identifying the best locations to site resources with minimal grid impacts, as well as for PJM to run network upgrade studies in parallel and to identify which projects are the most likely to succeed in reaching commercial operation. Souder said this will become increasingly important as the resource mix changes and it becomes more difficult for transmission owners to take lines down for outages. 

One of the challenges PJM and the electric industry face when integrating new technologies is the availability of data scientists. Out of the hundreds of programs PJM has designed in-house or through contractors, Hendrzak said they tend to be written by the same groups of industry-specialized engineers. 

Stakeholders Endorse GDECS Revisions

The committee endorsed a slate of revisions to PJM’s governing documents recommended by the Governing Document Enhancement and Clarification Subcommittee (GDECS), the most notable of which was changing several references to “end-use customers” to be lowercased. Changes also included removing outdated terminology, grammatical corrections and updating cross references. 

PJM Counsel Daniel Vinnik argued the uppercasing of end-use customer in multiple sections related to energy efficiency and demand response was an error and was not meant to limit participation in those programs to PJM members in the End-use Customer sector. He said PJM’s implementation of the language has remained the same before and after the uppercasing and noted the formatting was inconsistent throughout the sections. 

Paul Sotkiewicz, of E-cubed Policy Associates, said he’s concerned about making substantive changes through the GDECS process rather than bringing the revisions through the stakeholder process with an issue charge. He argued that some of the uppercasing may not have been an error, particularly in Schedule 6 language around energy efficiency. 

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Study: PJM Queue Wait Times Contributing to Longer Construction Periods

Lengthy wait times in PJM’s generator interconnection queue are interacting with siting and permitting timelines, supply chain disruptions and inflation to contribute to increasingly long construction periods, according to a study released last week by Columbia University’s Center on Global Energy Policy. 

The report, “Outlook for Pending Generation in the PJM Interconnection Queue,” surveyed 30 developers with projects in the “advanced stage” of the queue regarding the amount of time it would take for them to reach commercial operations after receiving an interconnection service agreement (ISA) and what major roadblocks could stymie those projects. 

“The key finding from the survey is that PJM’s increasingly lengthy interconnection process is exacerbating siting and permitting challenges and leading to knock-on delays in equipment procurement and financing decisions, suggesting the timeline for new generation in this market will likely remain long for the foreseeable future,” wrote the authors, Abraham Silverman and Zachary A. Wendling. “Given the importance of new entry to keeping prices competitive and maintaining reliability amid the retirement of older fossil resources, PJM will need to find ways to reduce interconnection delays or reconsider when those fossil resources should be retired.” 

The amount of time for a project to go from design to completion has been increasing over the past five years, the study said, and in PJM, the time it takes for a new interconnection service request to receive an ISA has increased from two years to five. 

If they were to receive an ISA today, participating developers said about 1% of the 249 projects they collectively have in PJM’s queue would be able to reach commercial operation within a year, while 26% could be completed within two years and 45% would take even longer. Among the 28% of projects with an in-service date conditioned on factors that made completion difficult to predict, siting and permitting was the largest source of uncertainty, along with supply chain constraints and the cost of transmission upgrades. 

Because local siting approvals and permits tend to be valid for up to two years, developers said uncertainty around their timelines for receiving an ISA has led many to wait until their interconnection studies have been complete to seek new permits, which can add time to how long it takes projects to get off the ground after PJM has completed its studies. 

One developer interviewed as part of the study described the interaction between the queue and permitting as “a bit of a chicken-and-an-egg problem: Ideally you would time these things so [permitting and construction] would come together, but until you have some kind of certainty that you are going to get an interconnection, we’ve been unwilling to make massive spending on permitting.” 

State regulations and siting requirements can complicate the matter as well, with West Virginia and New Jersey called out by developers for having rules that prove difficult for solar developers to navigate, and local authorities opposed to projects subjecting them to “a never-ending appeals process.” 

Offshore wind developers said federal regulators desire flexibility around projects’ points of interconnection or turbine designs, changes that can trigger PJM to restart the interconnection process. 

The study also questioned a central premise of the cluster-based interconnection process PJM embarked on this year: that many developers were submitting multiple interconnection requests for the same project to determine which point of interconnection would result in the least expensive network upgrade allocation. Part of the justification for including increasingly large readiness deposits as proposals progress through the queue was to weed out speculative projects. (See FERC Approves PJM Plan to Speed Interconnection Queue.) 

“The extent to which these duplicative requests slow down PJM’s efforts to complete interconnection studies has been hotly debated, and several of PJM’s recent queue reforms were designed to eliminate them,” the study said. “In the sample, only one developer identified an interconnection queue request that had been suspended or paused because it was extremely similar to another project with a separate queue position. Given this issue has been a major theme in PJM discourse, it was surprising to find only a single instance of it among … all the projects in the survey, though it is possible that developers are unwilling to self-report filing a duplicative or speculative interconnection request.” 

PJM spokesperson Jeff Shields disputed the report’s finding that speculative projects did not contribute to the queue backlog, saying there were 734 projects eligible for study when the RTO began implementing the new study approach last year, 118 of which dropped out or did not meet the new readiness requirements. 

He said most of the issues the report laid out are being addressed by the revised process, which has been on pace since implementation began last summer and is expected to clear about 72 GW of generation by mid-2025 and 230 GW over the next three years. The approach is designed to streamline the process for developers and provide more “transparency, certainty and equity,” Shields said in an email. 

“The delays for new projects are related to the fact that there are such a high number of megawatts in the queue ahead of them. What’s more concerning is the 450-plus projects totaling nearly 40,000 MW that have cleared PJM’s study process without moving to construction and operation due to siting, financing and/or supply chain challenges not related to PJM’s process,” he wrote. 

Shields said network upgrade costs should pose minimal barrier for the 26 GW of projects sorted into the expedited process, which places proposals in a fast lane if they’re allocated less than $5 million in upgrades. 

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Stakeholder Soapbox: It’s Time for New Wires on America’s Grid

An overlooked federal goal released alongside the Biden administration’s new power plant emissions standards could have an outsized impact on our power grid. 

The Department of Energy’s goal of upgrading 100,000 miles of existing transmission lines by 2030 comes alongside utility claims that rising demand imperils grid reliability. An existing but underused technology — reconductoring with advanced conductors — can help utilities and grid operators overcome these problems. 

In 2005, Xcel Energy urgently needed to bring more energy into Minneapolis-St. Paul, but the constrained urban environment made building new transmission difficult. Existing transmission lines intersected two major highways, crossed residential and industrial zones, and passed through protected wetlands and a National Wildlife Refuge. Permitting new towers and wires risked delay, extra cost and potential failure. 

Xcel instead decided to replace the existing line with higher-performance wire, increasing transmission capacity along the same route by using the same towers. This “reconductoring” wire replacement process greatly accelerated permitting. After eight weeks of construction, Xcel doubled the line’s ampere rating. 

New research from GridLab and the Goldman School of Public Policy at the University of California, Berkeley is the first estimate of potential clean generation deployment and cost savings that could be unlocked by reconductoring lines with advanced conductors. Replacing standard aluminum conductor steel-reinforced (ACSR) wires with advanced conductors can double a line’s capacity within existing rights of way at typically less than half the price of new line for similar capacity increases. 

Reconductoring is a pathway to spur nearly four times more interzonal transmission capacity expansion by 2035 compared to the average new-build transmission rate. This can help provide the majority of near-term interzonal transmission capacity needs to bring to market the 2,600 GW of cheap clean energy currently clogging interconnection queues. 

Reconductoring can’t meet all the needs of a low-cost clean energy system, but it can buy time to site and develop the new lines needed for long-term needs. Simultaneously reconductoring with advanced conductors and addressing barriers to new greenfield transmission provides the largest savings in total system costs of all considered scenarios: more than $400 billion by 2050 compared to business as usual. 

| Energy Innovation

The conclusion seems simple: Planning engineers and policymakers should find every place where cost-benefit analysis shows reconductoring with advanced conductor makes sense, then determine how to proceed. Unfortunately, nothing is simple when it comes to the bulk power system. 

A companion report from Energy Innovation and GridLab identifies the barriers that have historically slowed use of advanced conductors and the policy recommendations to add advanced conductors onto the grid as quickly as possible. 

Advanced reconductoring is stuck in the middle when it comes to cost recovery. Because it is a lower capital investment, monopoly utilities are instead incentivized to build entirely new lines. Advanced conductors also cost more than traditional wires, and regulators may view them as an unnecessary expenditure that gold-plates the system. A short-sighted, least-cost planning mindset for transmission owners makes it hard to accurately assess these benefits compared to either building new lines or using conventional conductors, so advanced conductors fall by the wayside. 

New policies at the state and federal level can help ISO/RTOs get the most from this technology. State regulators and legislatures should proactively develop a policy position for advanced conductors, helping expedite planning at the state and ISO/RTO level. For example, RTOs lack the information to second-guess TOs’ determinations that reconductoring with a traditional conductor or greenfield transmission could be done with advanced conductors. State policymakers can also support education and workforce training in reconductoring. 

FERC’s efforts to enhance regional planning processes can significantly improve resilience and integrate low-cost renewables through including advanced conductors. The rule approved by FERC on May 13 aims to modernize these processes by mandating forward-looking planning with a 20-year horizon, making the advantages of advanced conductors — increased transmission capacity and efficiency — more apparent in cost-benefit analyses. As regions update their compliance with this rule, especially in defining which benefits to weigh against costs, FERC can advocate for including conductor efficiency as a key factor in these evaluations. 

Beyond recent rulemakings, FERC should also consider creating independent transmission monitors (ITMs). Many states lack substantial review over transmission planning; in California, for example, 63% of projects from 2019 to 2022 were self-approved as “repair and replacement” projects. Non-RTO regions are not required to produce data allowing stakeholders to study, expose and challenge incumbent utilities to explore reconductoring or other transmission expansion to benefit consumers. ITMs could add data transparency and transmission planning expertise capacity for states and regions to objectively evaluate transmission projects and ensure TOs consider projects that add significant value to customers at lower cost, like reconductoring with advanced conductors. 

America’s grid needs new wires. Advanced reconductoring is ready. Now it’s time to implement the technology. 

Eric Gimon is a senior fellow with Energy Innovation.

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Environmental Groups Urge CEC to Fund EV Truck Chargers

Environmental groups are urging the California Energy Commission (CEC) to use the state’s remaining $233 million in National Electric Vehicle Infrastructure (NEVI) funds to build chargers for the surge of electric trucks expected in the next decade, citing “immense public health and environmental justice benefits” for communities with poor air quality.  

“As we know, the transportation sector accounts for half of the greenhouse gas emissions in California when you include upstream refining,” Jim McKinney, manager of the CEC’s fuels and transportation division, said during the agency’s May 10 NEVI workshop. “Our state’s one million trucks represent just 3% of the total vehicle fleet of 30 million vehicles, but they account disproportionately for one-third of mobile source NOx [nitrous oxide emissions], one-quarter of mobile source GHGs, and nearly three-quarters of the known cancer risk from toxic air contaminants.”  

Funded by the federal Infrastructure Investment and Jobs Act, the NEVI program encourages EV uptake by developing a national network of 500,000 direct current (DC) fast chargers using $5 billion in funding to states allocated over five years. California’s share of the funding is $384 million. (See Calif. Looks to Streamline Process for Issuing NEVI Funds.)  

The state’s first NEVI solicitation, issued in October 2023, offered $40.5 million to six “alternative fuel corridor” groups designated for charger development. Awards are expected to be announced this month. The second tranche of funding will provide an estimated $110.2 million to the 17 remaining corridor groups to build 598 charging ports. Applications for that round of funds are due in November.  

‘Parade of Terribles’

McKinney referred to the impact of emissions from the trucking sector as “the parade of terribles” for California air quality and said the CEC is working to determine whether NEVI funds can be used for truck charging. Earthjustice called attention to the issue in comments submitted to the CEC regarding the NEVI plan in 2023.  

“We recommend NEVI formula funds be allocated for medium- and heavy-duty charging in a significant way, including deployment of $50 million in Years 2 and 3 ($100 million total) to help supercharge efforts to build out charging for medium- and heavy-duty vehicles,” Earthjustice wrote. 

The Greenlining Institute, an Oakland-based non-profit organization, also commented on the NEVI plan, calling attention to the importance of equity in transportation electrification.  

“To date, electric vehicle charging investments have historically been deployed in well-resourced, early-adopter, higher-income census tracts or ‘low-hanging fruit’ areas. Through a profit-driven deployment strategy, low-income communities of color are being left behind while continuing to face disproportionate pollution burdens,” The Greenlining Institute wrote. “If done correctly, the administration can capitalize on this opportunity to deploy charging infrastructure in communities affected first and worst by climate impacts, align with Justice40 goals, reach the IIJA goal of 500,000 new chargers by 2030.” 

Guidance and regulations from the federal Joint Office of Energy and Transportation say the primary purpose of NEVI is to build light-duty fast-charge stations. However, funds can be shifted to other uses when alternative fuel corridors are “built out,” the presentation reads.  

“One key challenge is that there are no nationally defined or agreed-upon standards for truck-charging connectors, charging power levels, station power, station configuration or amenities,” McKinney said.  

The CEC has asked the Joint Office for clarification on whether NEVI funds can be used for truck charging, and while the agency hasn’t received confirmation, charging and fueling infrastructure grants were used to build charging stations for trucks in the past, so it knows “it’s possible,” he said.  

The demand for EV truck chargers is growing. As part of AB 2127, the CEC publishes a biennial report assessing the EV charging infrastructure needed to meet the state’s goals of putting at least 5 million zero-emission vehicles on the road by 2030. The CEC expanded this year’s report to include modeling forecasts for heavy-duty charging and projected the need for 114,500 chargers to support 155,000 zero-emission trucks by 2030.  

“This is an immense need, especially considering how few operational truck chargers we now have in California,” McKinney said.  

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SPP Board of Directors/MC Briefs: May 7, 2024

CEO Sugg Warns of ‘Serious Challenges’ Facing the Region

AURORA, Colo. — SPP CEO Barbara Sugg warned the RTO’s Board of Directors and stakeholders last week that the grid operator faces new and stronger headwinds, even as it met its corporate goals’ first-quarter milestones. 

In delivering her president’s report to open the May 7 quarterly meeting, she said, “I tell people all the time what a great time [it is] to be in the electric utility industry, but it’s not without challenges.” 

Sugg then listed those challenges: “significant” load growth in recent years and more “unprecedented” growth in the foreseeable future; still more variable energy resources in the generation fleet and interconnection queue; the transition to clean energy resources outpacing the technologies needed to support them for reliability; performance issues with traditional resources that have historically been “extremely dependable and responsive”; transmission constraints; struggling to get new transmission built in a timely fashion; and a backlog of generators with interconnection agreements that are not yet online. 

“And if that wasn’t enough, extreme weather events are becoming more the norm than the exception,” Sugg said. “I say all this to say that what got us here will not get us there. 

“We’re facing serious challenges in the region. We must continue to work together to not only understand these challenges, but remain committed to resolving them.”

SPP’s corporate goals are tied to its strategic plan. Mitigating resource adequacy risks is tied for the No. 1 goal with cybersecurity, and no wonder: The grid operator has issued five resource or conservative operations advisories since early March, the latest because of threats from solar storms. 

The RTO’s other goals are enhancing extreme weather event readiness, optimizing the generator interconnection queue’s processing, advancing innovative transmission policies and continuing the western expansion. 

“A vital element of these goals is to focus on affordability,” Sugg said. “We are still looking for opportunities to increase value and decrease costs. … We are below budget so far this year. I’m knocking on wood in large part due to process improvements and exceptional negotiating skills. Of course, there are always things that come up throughout the year that may or may not have been on our radar or in our budget, but we’re keeping a focus on affordability.” 

As if to emphasize the complexities ahead for SPP, the U.S. Department of Energy on May 8 released a list of 10 proposed transmission corridors that could be eligible for a share of $2 billion in federal loans and special permitting under FERC’s backstop siting authority. (See related story, On the Road to NIETCs, DOE Issues Preliminary List of 10 Tx Corridors.) 

Most of the National Interest Electric Transmission Corridors (NIETCs) lie squarely in SPP’s current and planned footprints. They include the 645-mile Delta Plains and 780-mile Midwest-Plains corridors, both of which would link with MISO. The Northern Plains corridor could solve congestion issues in the Dakotas and Nebraska, while two more in New Mexico and Colorado could improve ties between the two major interconnections. 

FERC on May 13 will unveil its plan to accelerate long-distance transmission line development to meet rising power demand and bring a backlog of planned clean energy projects to the grid. 

Apparently, it’s nothing SPP can’t handle. The grid operator says it will evaluate the order, DOE’s NIETC notice and other “pertinent” rulings in coordination with its members and the Regional State Committee, which comprises state regulators.

“SPP is hopeful these initiatives will align with our strategic goals to continue removing the generator interconnection backlog and developing a long-range consolidated planning process,” spokesperson Meghan Sever said. 

SPP’s current and proposed RTO footprints. | SPP

Bylaw Changes for RTO West

SPP’s membership unanimously approved recommended bylaw changes from the Corporate Governance Committee related to the RTO’s western expansion and board compensation during a special member meeting. 

The CGC said the revisions to SPP’s bylaws and its membership are necessary to expand the RTO into the Western Interconnection. They include increasing the Strategic Planning Committee’s membership, considering diversity between the two interconnections when selecting organizational group participants and expanding terms specific to the Western Area Power Administration’s Upper Great Plains to the agency’s other regions. 

Separately, the board approved a package of 16 tariff revisions that include establishing a Western balancing authority area and managing transactions across the DC ties’ 510 MW of bidirectional capacity between the two interconnections. Settlements will be based on transmission service reservations during the market’s first four years. After that, they will be based on transmission congestion rights. 

“We will use a single-market optimization using these DC ties to bring value across both the West and the East, with the goal to bring price convergence across the DC ties,” said Bruce Rew, SPP’s senior vice president of operations. 

Lloyd Linke, WAPA-UGP’s regional manager, abstained from the Members Committee’s unanimous vote, saying he “fully supports” the changes but that the agency wants to keep its options open in addressing potential protests at FERC. 

American Electric Power, Evergy and the Natural Resources Defense Council’s Sustainable FERC Project also abstained. 

SPP has been working since 2020 with Western parties, some already members in the East, interested in joining the RTO: Basin Electric Power Cooperative, Colorado Springs Utilities, Deseret Power, Municipal Energy Agency of Nebraska, Platte River Power Authority, Tri-State Generation and Transmission Association, and three WAPA divisions. 

The prospective members would add Utah and Arizona to SPP’s 15-state footprint. 

SPP’s RTO West is a “true expansion,” in the words of board Chair John Cupparo. Markets+ is a contract service funded by its participants. RTO West is targeted to go live in April 2026. 

The approved bylaw changes for directors’ compensation will increase their annual retainer from $95,000 to $125,000. The CGC said the increase keeps SPP’s board compensation competitive and helps attract top talent. 

The committee said it slightly modified the compensation framework to eliminate fees paid for special board assignments, board advisory or liaison support, assigned meetings, and the board/committee meeting fee. Board members will receive additional fees for participating on nine committees and task forces, increasing their compensation by 6 to 15%. 

Sugg said the board’s total 2024 compensation of $1.54 million is 11% above forecast. She said a compensation consulting firm recommended an even greater increase. 

“You all are very well aware and witness on a near-daily basis just how engaged the board is and how collaborative they are and working with all of you,” she told stakeholders. 

The CGC will again review the compensation policy in 2025, Sugg said. 

SPP, SPS Reviewing April Outage

Sugg told the board and MC that SPP is reviewing a small, local load-shed event in New Mexico and will bring a full report to the Markets and Operations Policy Committee’s meeting in July. 

The April 28 outage lasted for about two hours and represented about 3% of the area’s load. Southwestern Public Service, the local transmission owner, said about 1,000 customers were without power. 

“As with all operational events, we take these very seriously and are working through the after-action steps,” Sugg said. She said SPP and SPS staff, along with the Operating Reliability Working Group, are involved in the review. 

SPS said in a statement it was directed to reduce load to address voltage issues in the southern portion of its service territory.

“The specific drivers behind this event and steps to minimize recurrence remain a topic of discussion between SPS and [SPP],” it said. 

2023 Annual Report Released

SPP has released its 2023 annual report highlighting the previous year’s accomplishments, which resulted in $3.6 billion in benefits to its members and a 20:1 cost-to-benefit ratio. Sugg said lower gas prices, “substantial” load growth and an increase in wind energy were the primary drivers. 

Using a calculation vetted several years ago by stakeholders, the grid operator found members realized $2.25 billion in benefits from the markets and a combined $1.88 billion from transmission and operations and reliability. That was partially offset by $524.6 million in the transmission revenue requirement’s costs. 

“We certainly are delivering significant value to the region,” Sugg said. 

Dowling, Janssen Leave SPP

Midwest Energy’s Bill Dowling (left) and Kelson Energy’s Rob Janssen share a final moment together after their last board meeting. | © RTO Insider LLC

Sugg led standing ovations for Midwest Energy’s Bill Dowling and Kelson Energy’s Rob Janssen, who were both attending their last board meeting. 

Dowling has announced his retirement, and Janssen’s company is selling off its interest in Dogwood Energy, a 665-MW gas-fired generator in Oklahoma that serves as its only resource in SPP. 

“Lots of people come and go from this committee, but we would be remiss if we didn’t stop and recognize the fixtures, those people that really helped us become the organization that we are,” Sugg said. “We’ll miss both Bill and Rob.” 

Dowling and Janssen have both served as MOPC’s chair and spent more than 20 years on the MC. Dowling was also a founding member of the Regional Tariff Working Group. 

“I asked [Bill] if I could blame him for the 8,000 pages in our tariff, and he said, ‘No. Only the first 3,000 pages,’” Sugg said. 

Board Approves RSC Revisions

The board and MC approved three RSC revision requests that commissioners previously endorsed unanimously — as they did for all seven of their voting items — during their May 6 meeting: 

    • RR607 implements policy changes to the safe harbor provisions approved last October to provide more flexibility for market participants. The measure replaces the original 125% peak load criterion to not exceed the transmission customer’s projected system peak responsibility multiplied by the higher of 125% or the sum of 110% and the current planning reserve margin percentage. The policy reflects SPP’s recent establishment of a PRM. 
    • RR605 defines an authorized outage, adds requirements for resources’ availability during both the summer and winter seasons (unless on an authorized outage), and helps load-responsible entities and generation owners better understand when to submit RA capacity when providing workbooks to meet the RA requirement. 
    • RR616 ensures any outage not approved by the SPP balancing authority and not an outside management control event is accounted for in performance-based accreditation. Three renewable energy interests abstained from the MC advisory vote, with the Sustainable FERC Project’s Christy Walsh expressing concerns over SPP’s “piecemeal” approach to RA that could lead to additional tariff filings at the commission. 

The board’s consent agenda resulted in the approval of the 18-person industry expert pool that will judge bids for competitive projects within the SPP footprint. A panel of three to five experts will be chosen from the pool for each competitive upgrade. Sixteen of the members were renewed, and two new members were added. 

Other items on the consent agenda included: 

    • RR555, which implements two recommendations FERC made to SPP after the 2021 winter storm: that transmission operators and balancing authorities include new guidelines in their emergency operating plans to facilitate rotating load shed and protect critical gas infrastructure. 
    • An out-of-cycle request by Evergy Kansas Central to re-evaluate a 138-kV terminal upgrade near Wichita. 
    • Withdrawing a WAPA-UGP 345/230-kV transformer project in Fort Thompson, S.D. WAPA’s estimate of $59.17 million exceeded the $36.34 million variance bandwidth and would have delivered the project 10 years late. 
    • Approval of a $35.95 million refined cost estimate for SPS’ Potter County 345/230-kV transformer project. SPS’ estimate exceeded the $35.91 threshold, but staff said approving the economic project will allow the company to proceed and economically benefit the region. 
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Seams Concerns Won’t Drive Day-ahead Market Decision, BPA Says

The Bonneville Power Administration’s choice of a day-ahead market will not be driven by concerns about the impact of the seams that would divide the two markets proposed for the West, an agency official made clear May 8. 

“Bonneville is very aware that having two markets in the same or neighboring footprints presents seams that need to be managed. We are taking that into account,” Russ Mantifel, BPA director of market initiatives, said during a virtual workshop with stakeholders. “But we think seams are manageable and that the existence of seams does not mean a categorical rejection of us joining Markets+.”  

The workshop was the agency’s sixth such meeting on day-ahead markets and the first since agency staff issued its April 4 recommendation that BPA choose SPP’s Markets+ over CAISO’s Extended Day-Ahead Market (EDAM). (See BPA Staff Recommends Markets+ over EDAM.) 

BPA’s position on seams puts it squarely at odds with EDAM’s most ardent supporters, who contend that a West divided into two markets would hamper the region’s ability to fully tap the “diversity benefit” of its energy resources and varying load patterns. For those stakeholders, a single Western market with no boundaries represents the key reason for advancing toward a more organized electricity market. 

Included in that camp are the industry stakeholders and state energy officials backing the West-Wide Governance Pathways Initiative, an effort to create the governance framework for an independent market that expressly includes the state-run CAISO and builds on the ISO’s market platform.  

“The seams issue is kind of a core question here,” Fred Heutte, a senior policy analyst at the Northwest Energy Coalition (NWEC), said during the workshop. NWEC has been a longtime advocate for a single Western market. 

Heutte asked for BPA’s views on a February study by the Western Power Trading Forum (WPTF) and Portland, Ore.-based Public Generating Pool, which found that a seam between EDAM and Markets+ likely would create challenges beyond those seen at the boundaries of the full RTOs in the Eastern U.S., given that each market still would contain operating seams within them. (See Western Market Seams Issues to Differ from East, Study Finds.)  

Heutte linked his question to a comment in the BPA staff recommendation in favor of Markets+ that referred to the “complexities” of BPA needing to accommodate transmission customers (including Northwest investor-owned utilities) and “preference” customers who are not participating in Markets+ — or, possibly, either market. 

“This is a really unique situation,” Heutte said. 

“I would say for Bonneville, it’s not that unique,” Mantifel responded, noting that BPA for eight years served customers participating in CAISO’s Western Energy Imbalance Market (WEIM) before joining that market in 2022.    

“Just to be clear about this, I believe Bonneville has lived and resolved these seams more than any other entity in the West,” Mantifel said. “We have managed flows on our system for a market that we are not participating in, that we don’t control the redispatch of outside of the coordinated transmission agreements.” 

“The seams are important. We hear the comments about seams. But Bonneville does feel that there’s a way to make this work. We would encourage, we would invite FERC, for example, to get involved and encourage the market operators to work together,” he said. 

‘Profound Difference’

Heutte said there is a “profound difference” between how the real-time — and voluntary — WEIM functions and how transmission must be handled in a day-ahead market, which would require prior commitment of both resources and transmission.  

Heutte encouraged workshop participants to read the SPP-MISO joint operating agreement to get a sense of the complexity of transacting across market seams, calling the document a “sobering read.” Given its role as the major transmission provider in the Northwest, BPA’s positions would be even more complicated if it joins Markets+ while many of its neighbors join EDAM, he said, because both markets effectively would be running on top of its balancing authority area. 

“With all the complexities … [involved] with all the different potential positions of preference customers and transmission customers of Bonneville, this is a very, very complex thing to grapple with. I think it’s really important to understand this is not the same as just merely an extension of EIM,” Heutte said. 

Mantifel said BPA understands that complexity “as well or better than anybody.” The agency has already put a lot of thinking into the issue as an open access transmission provider, he said. 

“We understand the differences, and we do think that there are very feasible methods of reconciling all these things and operating,” he said. “We have done this, we think we can continue to do it, we think we can build on what we’ve done before and make it work.” 

‘Multilateral’ Issue

Lea Fisher, representing the Western Public Agencies Group (WPAG), asked if BPA will address the implication of seams in the business case accompanying its final decision of day-ahead market, “beyond the discussion you’ve included in the staff leaning where you outlined kind of the need to work through seams and some of the history and successfully doing that.” 

Mantifel said the Western Markets Exploratory Group (WMEG) studies prepared for BPA by Environmental+Energy Economics (E3) offer a picture of the economic benefits the agency would realize under multiple market footprints. (See Study Shows Uneven Benefits for Calif., Rest of West in Single Market.) E3 will provide “additional sensitivities” related to studies based on varying assumptions about transmission rates and “general market friction” at the seams, he said. 

In terms of the “operational nature” of the seams, Mantifel said BPA is “eager” to have discussions with others in the region on the subject but hasn’t “been able to find partners” for such talks. 

“But we will use the best information available, including our own experience, in terms of operationally what we think scenes would look like. That being said, seams are definitively multilateral. Bonneville can’t, on its own, make all the decisions or resolve all seams,” he said. 

Asked what steps BPA has taken to find willing partners for the seams discussion and whether it has reached out to CAISO, the agency told RTO Insider in an email: “The West appears to be on … track for two day-ahead markets to operate concurrently. BPA is just saying the time to consider seams issues in that environment is now. BPA stands ready to work with entities in the regions to dig into the issue.” 

The need to address seams was a topic of discussion at an April 30 meeting of the Markets+ Participants Executive Committee (MPEC). (See SPP’s Stakeholder Process Attracts Markets+ Participants.) 

“It’s not a secret to anyone that the biggest scenario around objection to Markets+ is the seam,” said MPEC Chair Laura Trolese, with The Energy Authority. She said it would “behoove” the committee to start working on ways to reduce “transactional friction” as soon as possible rather than waiting until the end of the year.  

Speaking at that meeting, Carrie Simpson, SPP’s director of seams and Western services, said RTO staff has heard “loud and clear that we want to figure this out.”  

“I think there’s still just confusion on how it works if we do nothing, and so I think starting there can help people identify what friction exists and what friction does not exist,” Simpson said. “It’s a very important issue to address, and so I think we let that [stakeholder] process play out.” 

But some stakeholders think that discussion would be premature before entities in the West decide which day-ahead market to choose. 

“We can’t really tackle this until we know where the boundary is,” WPTF Executive Director Scott Miller said last month at the spring joint meeting of the Committee for Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB). “And so, when we get to that point, I think sometime this year, then we can engage meaningfully in what we can do to manage the seams that are unique to the day-ahead market.” (See Western Officials Get Rundown on ‘Irritating, Inefficient’ Market Seams.) 

During the BPA workshop, Oregon state Rep. Mike Gamba asked what the advantage to the Northwest would be “in BPA being in a different market that outweighs the obvious difficulties resulting in creating an unnecessary seam.” 

Mantifel said that notion assumes the two markets are equal. 

“I would say that what we’re trying to articulate is that Markets+ is a superior option for us, and I think what we’re trying to move away from is the notion that these things are equal and that the only difference is one creates seams and another does not create seams,” he said. 

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MISO, PJM Agree to Perform New Type of Joint Transmission Study

MISO and PJM announced they will embark on a new joint transmission study in the latter half of this year that concentrates on upping their interregional transfer capability.  

The RTOs said they will be on the hunt for “opportunities for near-term transmission enhancements along the seam.” The study would have MISO and PJM conducting joint transmission analysis and coordinated modeling. 

The grid operators said increasing transfer capability between them could help overcome extreme weather and challenges posed by growing shares of intermittent resources in their fleets.  

MISO and PJM said their announcement is driven by a chorus of calls for better interregional planning from the Organization of PJM States (OPSI), the Organization of MISO States (OMS) and the Midwestern Governors Association (MGA). OMS and OPSI sent a joint letter to the RTOs in February calling for more in-depth joint planning. Multiple environmental and consumer advocacy groups also penned their own joint letters asking MISO and PJM to undertake more comprehensive cross-border planning. (See MISO, PJM Stakeholders Call for Interregional Transmission Overhaul.)  

MISO and PJM’s announcement comes as FERC seems close to setting minimum levels of interregional transfer capacity and after the introduction of the BIG WIRES Act in Congress, which also calls for establishing minimum transfer requirements.  

PJM Vice President of Planning Paul McGlynn said PJM looks forward to more planning coordination with MISO. 

“Ensuring a reliable energy transition requires greater interdependence among regions and careful planning. Advancing this enhanced effort will benefit electricity consumers in each region,” McGlynn said in a May 9 press release.  

MISO Vice President of System Planning Aubrey Johnson said MISO and PJM have a long history of working together.  

“[W]e understand the need to explore interregional planning, and with encouragement from OPSI, OMS and MGA, we will conduct a study that will address both near-term needs and create a model for future studies,” he said.  

The newest MISO-PJM study effort is considered separate from their usual interregional planning processes, which include coordinated system plans that can result in larger interregional market efficiency projects or the smaller, quicker targeted market efficiency project (TMEP) portfolios. It’s not clear yet what projects will result, or if MISO and PJM will create a new class of interregional projects following the study.  

“Similar to MISO and SPP’s [Joint Targeted Interconnection Queue studies] as a new venture in interregional planning, this study between PJM and MISO is also a new venture to enhance interregional planning,” MISO and PJM said in a statement to RTO Insider. 

MISO and PJM said they believe the study “will provide a pathway to increase transfers between the two systems through near-term enhancements, working in collaboration with states and members.”  

Historically, the two approved one interregional market efficiency project in 2020 and have approved four sets of the  smaller  TMEPs aimed at relieving congestion since 2017. They haven’t completed an interregional transmission planning study since 2022. 

MISO and PJM’s plans to coordinate their models for this study does not mean they will work from a joint model. The RTOs said their respective subject matter experts will work together “very closely” to line up assumptions to identify transfer needs and fixes that could expand flows between footprints. They said the new study could provide some “future opportunities” for seams modeling improvements.