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.
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.
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.
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.
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.
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-MISOjoint 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.”
“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.
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.
FERC is taking the rare step of holding a special open meeting May 13, a Monday, to vote on a proposal to overhaul its transmission planning and cost allocation rules (RM21-17).
The order would mark the first time since Order 1000 was issued more than a decade ago that FERC made universal changes to those rules. If fully approved as issued, the Notice of Proposed Rulemaking, which the commission issued in 2022, would require longer-term planning out to 20 years with multiple scenarios, create a process for states to agree on cost allocation for regional lines and expand the federal right of first refusal (ROFR) after Order 1000 largely eliminated it.
One of the big issues generating debate around the rule is what FERC might do in terms of setting rules on its own if those state talks on cost allocation fail. Commissioner Mark Christie consistently has said states should not be forced to pay for others’ policies, while supporters of broader cost allocation have said transmission lines can offer broad-enough benefits to warrant wide cost allocation. (See FERC Observers, Stakeholders Lay out What is at Stake with Tx Rule Looming.)
The ROFR issue also has split the industry between those who argue the move to competition has stifled development and those who maintain that rolling back competition would lead to higher costs for consumers in what promises to be a massive buildout of transmission in the coming decades. (See Pro-competition Group Plans to Sue if FERC Reinstates Federal ROFR.)
The commission also will vote to update its backstop siting authority, as required by Congress, that would allow it to approve a line in a National Interest Electricity Transmission Corridor when a state denies the application before it (RM22-7). DOE recently announced a preliminary list of NIETCs. (See related story, On the Road to NIETCs, DOE Issues Preliminary List of 10 Tx Corridors.)
The planning proposal has drawn support from around the U.S. and across the aisle, such as Kansas Gov. Laura Kelly (D) and a group of House Republicans from New York led by Rep. Andrew Garbarino.
Less than a week ahead of the meeting, the EFI Foundation, led by former Energy Secretary Ernest Moniz, released a report that endorsed the NOPR’s main proposals. It argued the country is failing to proactively build transmission lines needed to connect new generation to customers, with the problem growing more acute because of new sources of demand.
“New load that requires new power is growing today, but regional transmission typically takes at least a decade to build,” the paper said. “New power capacity (including all kinds of generator technologies and storage systems) could deploy faster if transmission capital investments could be more quickly planned, agreed upon and constructed by the nation’s regional transmission system operators.”
FERC’s proposed rule includes many of the best practices that draw on real-world experiences of ISO/RTOs over the past decade, and many have said it should ameliorate the lack of transmission expansion.
“But some will question whether FERC has the statutory authority to prescribe and direct jurisdictional transmission organizations to enact those reforms, as opposed to simply making suggestions and recommendations,” EFI’s paper said.
Another school of thought argues FERC has broad authority to require transmission planning and cost allocation, having won the appeals of Order 1000 a decade ago, when a federal court found it had the authority to require transmission planning for needs driven by public policy.
But the EFI report noted the Supreme Court’s composition has changed since then, and its “major questions doctrine” could be a boon to opponents.
“While never used explicitly in a major opinion, this doctrine suggests that in issues of major national significance, agencies may need to be granted clear statutory authority by Congress rather than relying on interpretations of more general delegated authorities,” the report said. “Through this lens, they may argue that prior legal decisions should be revisited to ensure that regulations are supported by clear congressional authorities.”
New sources of demand growth such as data centers for artificial intelligence and rising industries are complicating electricity load forecasting, according to a new report released by The Brattle Group on May 8.
“Currently, there is a wide spectrum among utilities in how they account for these new drivers,” T. Bruce Tsuchida, a Brattle principal and co-author of the report, said in a statement. “The future net load growth spurred by the new drivers is vast, and our analyses suggest that — given this growth, along with the change in load characteristics and other associated uncertainties — the industry will require a revamped approach to load forecasting moving forward.”
NERC recently raised its compound annual growth rate (CAGR) for load from 0.6% per year to 1.1% per year over the next 10 years, which is higher than at any point in the past decade. FERC Form 714 filings from utilities have shown peak demand growth rates increasing from 2.6% in 2022 to 4.7% in last year’s filings, Brattle’s report said.
The new demand drivers and their changing nature and flexibility warrant looking at load forecasting from a different perspective, it said.
“In today’s world, where much of these new demand drivers are policy-driven, the risk of under- versus over-forecasting is asymmetric,” the report said. “With a climate strategy that relies heavily on clean electrification, the cost and long-lasting effects of underforecasting may be much larger than those of overforecasting — while still recognizing that large overforecasts also have accompanying costs.”
Policies aimed at combating global warming are driving some of the new demand, but in some regions, new data centers are having a major impact on load growth. Data centers use about 19 GW of capacity now, but with a 9% CAGR, the sector is expected to add the equivalent of New York City’s demand over the next five years nationally.
“The number of data centers is growing rapidly to meet increasing data usage from streaming services, social media, mobile devices and cloud computing, just to name a few,” the report said. “The emerging fields of AI and machine learning require massive computational power and storage, fueling demand for data center infrastructure and, with it, the demand for electricity. These loads tend to run constantly.”
Cryptocurrency mining uses an estimated 10 GW to 17 GW across the country, and its growth is volatile and based on crypto prices, but it could grow by an additional 8 GW to 15 GW by 2030.
Type A vs. Type B
However, the biggest potential source for growth this decade, Brattle reports, is hydrogen production, which could increase from just 70 MW to 25 GW of demand by 2030, which works out to 132% growth yearly.
The load growth drivers can be classified in two basic ways: “Type A” loads that are large and discrete and often characterized by more uncertainty, and “Type B” loads that are comparatively smaller with smoother growth patterns.
Load growth from electrifying transportation and buildings counts as Type B, but the industry still faces significant uncertainty around its long-term trajectory.
“Load growth from electrification, which naturally requires replacing existing stocks, takes time to materialize and is usually geographically uneven,” the report said. “This contributes to higher levels of uncertainty in these forecasts.”
Data centers, new industry, indoor agriculture and cryptocurrency mining are Type A. “These loads are often quite large and lumpy (sometimes as large as an entire city),” the report said. Their expansion is also concentrated in specific areas and their development can move faster than utility or ISO/RTO planning processes.
The new loads can change suddenly due to shifts in the market or policy and in some cases — such as with cryptomining and indoor agriculture — they can disappear without notice.
“Some of these loads may be able to provide flexibility, so the conventional assumption that planning requires building enough capacity to serve an inflexible peak load may no longer be true,” the report said.
Even without local flexibility, efficiency, demand response and distributed energy resources can offset potential load or sales growth. Those demand-side resources can be large and cost effective for freeing up supply increments for high-priority uses.
Brattle collected load forecasting documents from utilities and ISO/RTOs around the country for the report and found a spectrum of ways entities are dealing with the new drivers of demand. Traditional load forecasting methods assumed that new demand would be inelastic and that future needs could be addressed within a long planning horizon, usually measured in years.
“One of the first steps planners could take today is to comprehensively assess the various drivers, even if a sophisticated modeling approach is not yet available,” the report said. “The latter should come next after the new load types are better understood.”
Republican state attorneys general sued EPA on May 9 seeking to stop implementation of the agency’s final rule aimed at slashing greenhouse gas emissions from existing coal plants and new natural gas plants.
Under the rule released April 25, existing coal-fired power plants nationwide will have to either close by 2039 or use carbon capture and storage or other technologies to capture 90% of their emissions by 2032. New natural gas plants will have until 2035 to similarly cut their emissions, through efficient design, carbon capture or a combination of both. (See EPA Power Plant Rules Squeeze Coal Plants; Existing Natural Gas Plants Exempt.)
The suit, filed with the D.C. Circuit Court of Appeals, is led by Indiana Attorney General Todd Rokita and West Virginia Attorney General Patrick Morrisey, the latter of whom led states’ successful lawsuit against the Obama administration’s Clean Power Plan. (See Supreme Court Rejects EPA Generation Shifting.)
“The EPA continues to not fully understand the direction from the Supreme Court; unelected bureaucrats continue their pursuit to legislate rather than rely on elected members of Congress for guidance,” Morrisey said in a statement. “We are confident we will once again prevail in court against this rogue agency.”
The National Rural Electric Cooperative Association filed its own suit against the rule with the D.C. Circuit the same day.
“EPA’s power plant rule is unlawful, unreasonable and unachievable. It exceeds EPA’s authority and poses an immediate threat to the American electric grid,” CEO Jim Matheson said. “Reliable electricity is the foundation of the American economy. EPA’s rule recklessly undermines that foundation by forcing the premature closure of power plants that are critical to keeping the lights on — especially as America increasingly relies on electricity to power the economy.”
Both suits are essentially placeholders, petitioning the court for judicial review and attaching the rule as evidence but making no arguments. They were filed a day after a separate suit — led by Morrisey and North Dakota Attorney General Drew Wrigley, and joined by 21 other Republican-led states — was filed with the D.C. Circuit challenging EPA’s updated implementation of the Mercury and Air Toxics Standards, announced by Administrator Michael Regan at the same time as the power plant rule.
“The Biden administration pushes a green political agenda with no purpose other than to attack fossil fuels. Make no mistake, this rule intentionally sets impossible standards to destroy the coal industry,” Wrigley said in a statement. “Federal agencies cannot decide on a whim to destroy entire industries. They are only permitted to work within the bounds that Congress set for them.”
EPA declined to comment on the pending litigation.
FERC on May 6 partially reversed a 2023 order allowing PJM to modify a parameter for the 2024/25 Base Residual Auction (BRA) to avoid a substantial increase in capacity prices in the DPL South transmission zone and instructed the RTO to rerun the third Incremental Auction (IA) (ER23-729-002).
The order increases the clearing price for the DPL South locational deliverability area (LDA) to $426.17/MW-day, up from $90.64 under the auction results PJM posted in February 2023 using the modified parameter. The LDA with the second-highest price is the DEOK region, which cleared at $96.24/MW-day.
In a series of notifications to stakeholders following the order, PJM said it will reopen bids for the third IA on May 10 through May 16; the auction was originally administered Feb. 27 through March 4. Market participants’ original sell offers and buy bids will be the default if no changes are submitted, while all bilateral and replacement transactions made since March 4 have been withdrawn by PJM.
FERC had granted PJM the authority to revise the reliability requirement for the zone, which covers the Delmarva Peninsula, after preliminary analysis of the BRA, held in 2022, showed a nearly fivefold increase in capacity prices because of an unexpected shortfall in offers. The change was made after the auction was run but before the results were published.
But in March, following challenges by several stakeholders, the 3rd U.S. Circuit Court of Appeals ruled that change constituted retroactive ratemaking, a violation of the Federal Power Act, as well as the filed rate doctrine. (See 3rd Circuit Rejects PJM’s Post-auction Change as Retroactive Ratemaking.)
The RTO had requested that the commission allow it to exclude resources that did not enter into the auction from the zone’s reliability requirement and to add tariff language permitting the parameter to be revised when resources expected to offer into the auction prompt the reliability requirement to increase by more than 1% but ultimately do not submit an offer. The court’s ruling and FERC’s order leave the forward-looking tariff language but require the original reliability requirement to be used for the 2024/25 auction and the third IA.
PJM filed a petition arguing that the only way forward would be for it to recalculate the BRA results using the unaltered reliability requirement and asked the commission to allow it to rerun the third IA. Several state commissions, consumer advocates and industrial groups jointly protested, making a case that FERC holds remedial authority and could direct PJM to continue using the revised parameter.
But FERC said the court had tied its hands.
“We find that the court’s opinion vacating the portion of the commission’s orders allowing PJM to apply the tariff amendments to the 2024/2025 BRA indicates PJM ‘was required to use’ the initial LDA reliability requirement,” FERC said. “In particular we note that, in reaching that result, the court reiterated that ‘the equities play no role in its application of the filed rate doctrine.’ Accordingly, while we acknowledge PJM load parties’ concerns about rerunning auctions and the equities implicated by this proceeding, we find that they cannot change the outcome here.”
Commissioners Reluctantly Concur
All three sitting commissioners separately expressed dismay with the outcome.
Chair Willie Phillips criticized the 3rd Circuit’s decision, saying its “broad reading of the filed rate doctrine, and its endorsement of ‘predictability’ as a higher virtue than equity, is beyond troubling and does not represent my views. … One must ask: If the over $100 million result of a ‘faulty assumption’ (and no one in this case argues that it’s not a faulty assumption) is somehow OK, what about a $1 billion faulty assumption, or a $1 trillion faulty assumption? Can we still conclude those are just and reasonable rates?”
Phillips urged “all stakeholders, including both PJM and the generators that will reap the more than $100 million windfall due to the court’s decision, to take all necessary steps to ensure that we never find ourselves in this position again. That includes putting in place controls to ensure that a similar error does not reoccur and, should it somehow happen again, that PJM or the commission has the authority to correct that error and protect customers from such a manifestly inequitable result. Basic equity, and the public interest, demand nothing less.”
Commissioner Allison Clements went a step further, saying that the commission could initiate a proceeding under FPA Section 206 to investigate whether RTOs lacking such protections may produce unjust and unreasonable rates.
“Should PJM and other public utilities fail to affirmatively update their tariffs to provide notice that adjustments can be made, where appropriate, to prevent inequitable outcomes, then it will fall to the commission to cure this failure pursuant to its authority under Section 206 of the Federal Power Act,” she wrote.
Her criticism of the ruling was also broader, saying that “it is only the latest in a string of unjust outcomes stemming from the courts’ narrow view of [the filed rate] doctrine” and citing a previous case. (See DC Circuit Upholds FERC Ruling on SPP Z2 Saga.)
Commissioner Mark Christie said “the complexity of PJM’s capacity market cannot be overstated” and raises the risk of oversights costing consumers.
He quoted his concurrence from earlier this year in FERC’s approval of PJM’s changes to its capacity market, criticizing it as increasingly incomprehensible: “Perhaps PJM should be required to post a warning to every reader who tries to read and comprehend a detailed explanation of how the capacity market construct works (borrowing from Dante): ‘Abandon all hope, ye who enter here.’” (See FERC Approves 1st PJM Proposal out of CIFP.)
“The tinkering and complexities here will assuredly impact consumers — who took no part in this tinkering but will surely pay for the complexities by way of what are estimated to be dramatic rate increases,” he said in his latest concurrence. “This … should require each and every one of us who have played some part in the tinkering (regulators, RTOs and market participants alike) to make certain that it is not consumers who must abandon all hope.”
Consumer Advocate Argues More Could have been Done
Maryland People’s Counsel David Lapp told RTO Insider he believes FERC had the authority to act differently.
“It’s extraordinary that we have three FERC commissioners … acknowledging that this is unfair to customers and customers are being getting hit with the consequences of this error and yet they are not using their authority to address that problem — and they have remedial authority,” he said. “FERC is responsible for setting just and reasonable rates; we know the rates are not reasonable, and yet customers are being forced to pay those rates.”
Without the power to resolve market design errors before rates go into effect, Lapp said he is worried similar circumstances could arise again. His office will be exploring tariff amendments that could be offered in the stakeholder process to empower PJM to correct issues before they hit consumers’ bills.
Lapp noted that the increased capacity costs will go into effect as Maryland ratepayers may be required to pay a share of a $263 million reliability-must-run (RMR) contract to keep the 410-MW Indian River Unit 4 generator online through December 2026. (See PJM Monitor and Consumers Protest Indian River Compensation Settlement.)
“This specific impact [from the capacity market] appears to be around $5/month, and there are additional impacts from the RMR for the Indian River plant retirement,” he said. “Maryland’s customers as a whole are getting hit very hard as a result of the consequences of this error — this error that everyone acknowledges is an error — but also as well as the planning processes, or lack thereof, at PJM.”
The Maryland Public Service Commission also criticized the order, arguing it would produce unjust and unreasonable rates, “though we appreciate each of the FERC commissioners’ expressed reluctance to have to approve PJM’s proposal,” spokesperson Tori Leonard wrote in an email.
“Rates will clearly be unjust and unreasonable. We can only hope this could be rectified somewhat, through the Incremental Auction. That is not to say that our commission is not weighing its legal options on this matter,” Leonard said.
Independent Market Monitor Joe Bowring said PJM’s effort to revise the reliability requirement may not have run afoul of the filed rate doctrine had PJM not sought to create a new rule enshrined in the tariff.
“They didn’t have to make it subject to a rule change. … They could have realized they made a mistake, fixed it and posted the correct numbers,” he said.
Bowring said it’s unlikely that rerunning the third IA will present participants with technical challenges around preparing new offers, which he said will be carefully reviewed to ensure that participants are not taking advantage of insight into how others behaved in the first iteration.
“It’s hard to predict; as always we don’t want people exercising market power. … It gives you an advantage to know what happened,” he said.
