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November 12, 2024

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IRC Urges FERC to Remand NERC Cold Weather Standard

Citing “glaring exceptions and vague requirements” with the proposed cold weather standards submitted by NERC last month, members of the ISO/RTO Council on March 21 expressed “united opposition” to their approval and urged FERC to direct the ERO to submit a revision addressing RTOs’ and ISOs’ concerns within the next four months (RD24-5). 

NERC filed EOP-012-2 (Extreme cold weather preparedness and operations) with the commission Feb. 16, the day after the organization’s Board of Trustees approved the standard at its open meeting in Houston. (See “Cold Weather Standard Accepted,” NERC Board of Trustees/MRC Briefs: Feb. 14-15, 2024.) It serves as successor to EOP-012-1, which FERC approved in February 2023 while ordering NERC to develop a replacement within a year. 

In its filing, the IRC emphasized that it supports the commission and the ERO’s efforts to prevent future major outages due to cold weather, such as those during winter storms Elliott and Uri, through the development of reliability standards. The council said it “has actively engaged” during all stages of the standards development process “to advocate for durable requirements that will lead to effective winterization” and “was careful to propose specific language to address the concerns it raised.” 

However, although the IRC acknowledged the standards drafting team modified the standard in response to some of its comments, it said the submitted standards leave the “most significant concerns … unaddressed.” It warned that approving the standard will lead to more reliability issues, causing additional work for FERC and greater cost for generator owners and the public. 

“It is admittedly unusual for the IRC members in the United States to unanimously urge the commission to reject and remand a NERC reliability standard,” the IRC wrote. “The IRC does not take this step lightly, but given … the need to ‘get it right’ rather than just ‘getting it done,’ the IRC urges the commission to carefully weigh the fact that the record reflects the united opposition of all the RTOs and ISOs throughout the [U.S.] (and the [Independent Electricity System Operator] in Canada) to the exceptions and low winterization bar included in the proposed standard.” 

Cost Concerns Misplaced, IRC Says

The IRC listed multiple issues with the standard, but a common theme was that NERC’s proposed requirements were “subjective [and] unclear.” 

For example, Requirement R7 of EOP-012-2 excuses generator owners from implementing freeze protection measures if those measures would cause a “generator cold weather constraint” — meaning that the measures cannot be “implemented at a reasonable cost consistent with good business practices, reliability or safety.” Unreasonable costs include “prohibitively expensive modifications or significant expenditures on equipment with minimal remaining life.” 

The IRC said this definition gives GOs multiple avenues to avoid implementing freeze protection measures, and forces NERC and the regional entities to judge the reasonableness and accuracy of an entity’s estimated costs. Pointing out that this is not normally the ERO’s jurisdiction, the IRC said the commission should direct cost-based constraints to be removed from the standard. Instead, IRC suggested constraints should be granted on a per-unit basis on grounds of technical feasibility, which the IRC observed falls under NERC’s expertise.  

In addition, the IRC warned the standard “provides far too much discretion to [registered entities] to interpret whether freeze protection measures are available for [their] equipment when determining whether a basis exists to declare a constraint.” It noted that the standard’s definition of “freeze protection measures” refers to practices and technologies “generally implemented by the electric industry in areas that experience similar winter climate conditions.” 

The council expressed concern this language would create difficulties with auditing the standard, because GOs could simply declare a constraint on the grounds that there are no available measures that are “generally implemented” by their peers. This could also “delay and disincentivize” the adoption of new technologies. IRC’s filing said the ERO should be directed to require measures that “would reasonably be expected to result in effective facility performance while operating at the extreme cold weather temperature.” 

Exemptions Too Generous

IRC also took issue with the standard’s exemptions for existing generating units. The standard exempts units from some winterization requirements if they “may be called upon to … assist in the mitigation of … emergencies during periods at or below a temperature of 32 degrees Fahrenheit.” IRC suggested that this exemption should apply only to “truly seasonal generating units that will not be called upon to operate during freezing conditions” so that units unsuited for cold weather are not called on in emergencies. 

NERC’s proposed timelines for implementing corrective action plans on units that experience cold weather-related emergencies — with entities’ required actions that can be completed within 24 and 48 months — were also a subject of the IRC’s criticism, with the council worrying that these periods “do not appropriately reflect the urgency of winterizing generating units.” It supported reducing the timetables to 12 and 24 months, along with requiring GOs to receive approval from NERC or their REs for longer implementation timelines. 

In a statement, NERC said that EOP-012-2 is part of a “suite of cold weather standards [that] are key to addressing” grid impacts of severe cold weather. The ERO pointed to EOP-012-2’s clarifications of applicability, GOs’ eligibility for exemptions and shortening the implementation timeline as “key modifications that build on the general framework and principles established in EOP-012-1,” and said NERC is committed “to monitoring the effectiveness of the standard.” 

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Overheard at CERAWeek 2024

HOUSTON — CERAWeek 2024 by S&P Global was supposed to explore “strategies for a multidimensional, multispeed and multifuel energy transition” and the energy industry’s response to growing demand for emissions reductions and cleaner forms of energy. 

However, the two buzziest words during the weeklong conference March 18-22 turned out to be “data centers” and “artificial intelligence,” or AI, and their effect on growing electricity demand. 

During one panel discussion, AES CEO Andrés Gluski noted the demand generated by data centers.  

“I’m glad you mentioned data centers,” interjected the moderator, S&P Global’s Xizhou Zhou, “because every session seems to have to mention data centers or AI.” 

“Coming out of the pandemic, we started to see demand increase two years in a row,” said Independent Electricity System Operator executive Chuck Farmer. “We’re less worried right now about data centers, but frankly, I wasn’t that worried about data centers until I came to this conference.” 

Energy Secretary Jennifer Granholm said the explosive growth of data centers, cryptocurrency miners and AI-fueled technologies is what keeps her up at night. 

Cryptocurrency miners have flocked to the U.S. after China’s 2021 crackdown on the industry. The U.S. Energy Information Administration says their energy demand could represent as much as 2.3% of electricity consumption, or 19 GW, according to the Cambridge Bitcoin Electricity Consumption Index (CBECI). 

The CBECI estimated the U.S.’s global share of crypto mining went from 3.4% in 2020 to 37.8% in January 2022. ERCOT has 41 GW of requests for new mining capacity in its interconnection queue; about 9 GW have been approved for planning studies, according to NERC. 

CERAWeek by S&P Global delegates take a break from the conference. | © RTO Insider LLC

“Energy demand has been sort of flat because of energy efficiency, and now all of a sudden we’re seeing this huge increase because of AI, because of data centers, because of Bitcoin, because of crypto, because of the additional manufacturing facilities that are coming online because of electrification of transportation,” Granholm said during her appearance. “As the AI revolution has come upon us, I think we have to think a little bit differently about how we ensure that we’ve got enough power.” 

Indeed. Experts say AI could be instrumental in creating additional energy efficiency and decarbonization tools. The DOE already has a pilot program to evaluate whether the huge amount of available data can speed up permitting timelines. 

“Here’s the hopeful thing,” Granholm said “We really think that AI can be really helpful on quick permitting because with these huge datasets of land characterization, for example, and a huge amount of information already in the public datasets that DOE has access to through our national labs, we think that machine learning can speed up significantly permitting times.” 

Microsoft co-founder Bill Gates said during his plenary session that AI can be used to determine the best ways to reduce demand at data centers that naturally will pop up where electricity is cheaper. AI also can be used to calculate emissions climate effects and improve efficiency. 

“All of our sort of grid modeling and management, these AI tools will come in and play a role,” he said. “But the current techniques require a lot of electricity.” 

Pattern Energy Eyes Next Project

Pattern Energy CEO Hunter Armistead, whose company recently broke ground on what may be the largest clean energy infrastructure project in U.S. history, a 550-mile HVDC line from New Mexico into southern Arizona, offered his own thoughts on speeding up transmission permitting. 

“Tight timelines to respond also have timelines for challenge,” Armistead said. 

Hunter Armistead, Pattern Energy | © RTO Insider LLC

Pattern’s SunZia Wind and Transmission project was placed on the drawing boards in the mid-2000s, back when Blackberrys ruled the business world and Taylor Swift’s “Love Story” first caught Armistead’s attention. 

“[‘Fearless’] was a badass album, by the way. I mean, I became a Swiftie early on,” he said. 

Pattern didn’t become involved in SunZia until 2018, and it secured FERC’s approval of its tariff only last year. All told, breaking ground on a project that should be commercially available within the next two years took 16 years. (See FERC Approves Tariff for SunZia Transmission.) 

“Sixteen years … we can’t do that again. We have to learn from this arc of time and figure out how to shrink it quite a bit,” Armistead said. 

While the project’s costs have risen to $11 billion and while Armistead said he hopes Pattern never does a deal that large again, he called SunZia a “transformative moment for our industry.” 

“Deals like this more naturally don’t get done. The part that really just struck home with me is how critical this was to so many people,” Armistead said. “My absolute hope for the future is that this is only the beginning. As an organization, Pattern has had the opportunity to learn what this all takes to do.” 

He said the company’s next “most ambitious project” is Southern Spirit, formerly known as Southern Cross. The project involves 320 miles of 525-kV HVDC transmission facilities interconnecting ERCOT with MISO and grids in the southeast. The project gained regulatory approval from the Texas commission in 2022 after seven years of review, and FERC has said Southern Spirit will not trigger its jurisdiction over ERCOT. (See “SCT Proceeding Closed,” Texas Public Utility Commission Briefs: Sept. 29, 2022.) 

“It is going to be even more awesome [than SunZia],” said Armistead, who said he told staff Southern Spirit is his favorite operational project. 

“The reality is the complexity of integrating to ISOs, the disparate weather patterns between what goes on in the southeast and the complication of integrating renewable generation that’s available to the southeast, yet being able to provide capacity back into ERCOT,” he said. “I have no idea how we’re going to structure the commercial side of it, but that’s what makes it super-duper fun.” 

Glick Doesn’t Miss Politics

Former FERC Chair Richard Glick popped up at CERAWeek’s Innovation Agora, the conference’s technology and innovation programming center, to promote Hydrostor’s compressed-air, long-duration storage. 

Glick told RTO Insider he is “fascinated” with the Canadian company’s technology. Hydrostor uses compressed air and water to store energy produced during the compression. The energy is then used to generate power when it’s released from underground rock caverns. 

Former FERC Commissioner Richard Glick lays out his support for long-duration storage. | © RTO Insider LLC

“We’re like a pumped hydro asset,” Hydrostor President Jon Norman said. 

One of consulting firm Glick & Quinlan’s clients raised the former commissioner’s awareness of long-duration storage, defined as eight hours or more. 

“There really is a need for longer storage, so I thought this was really kind of the right time to get in and talk about some of the policies. It’s been fun so far,” Glick said. “There are enormous benefits from an environmental perspective and from an economic perspective.” 

Glick, who left FERC after 2022 when the U.S. Senate’s Energy & Natural Resources Committee refused to hold a confirmation hearing, said he misses his work at the commission. (See FERC’s Work in 2022 Left in Doubt by Manchin.) 

“The issues are really interesting, obviously, and you’re in the middle of everything these days, for good and for bad,” he said. “I don’t miss some of the machinations, some issues that came up over time.” 

Perhaps aware that three potential successors would be going before the Senate Energy Committee, Glick added, “I certainly don’t miss testifying on Capitol Hill.” 

SMRs Could be Answer for Nukes

Texans have a reputation for talking big, and Jimmy Glotfelty is no exception. The regulatory commissioner has been tasked with leading a task force on whether the state can deploy small modular nuclear reactors (SMRs), but he’s not stopping there. 

“This is an opportunity for us to open the door and lay out the welcome mat that we are interested in nuclear,” Glotfelty said during an Innovation Agora pod discussion. “We want to hear from you. If you all want to build, if you need to de-risk projects and we can help you do that in some way, let us know what that way is. That’s what we want to do here.  

Jimmy Glotfelty, Texas PUC | © RTO Insider LLC

“We don’t want to be like every other state. We want to be ahead of every other state, and we want to build a business and an industry here for a global nuclear business,” he added. “That’s the way we are looking at this. Not to build one or two plants, but to build a community and to build an industry that will serve the world.” 

The task force must deliver a report to the governor and the Legislature by December that outlines how plants are built and designed, how sites are identified, and whether any changes to laws or ERCOT protocols need to be made. 

“We should look at nuclear plants in the long term like a dispatchable gas facility. I think as the cost curve comes down, [nuclear and gas] are going to be the same,” Glotfelty said. “That’s our expectation, that gas plants or nuclear plants can support the market’s reliability in an equal fashion.” 

Speaking on a separate panel, former U.S. Energy Secretary Ernest Moniz, now CEO of the nonprofit Energy Futures Initiative, said nuclear technologies come in several flavors besides SMRs and include micro-reactors, light water, heavy water, fourth generation, thorium, liquid metal and molten salt. 

Ernest Moniz, Energy Futures Initiative | © RTO Insider LLC

Moniz said his initiative has put together a suggestion to kick-start SMRs’ deployment, noting it is translatable to gigawatt-scale reactors. 

“The issue is getting an order book of sufficient scale to justify investments,” he said, suggesting the order book be put together by the government. “Government has a role to help this happen in the United States when it’s ultimately in the private sector, facilitating to share financial investment, because especially with a new design, the first reactor is likely to be substantially more expensive. If you can share the financial burden and price an order book for 10, 20 reactors or whatever you choose, that would be good.” 

That’s exactly what the U.S. government is doing for TerraPower’s planned Natrium reactor in Wyoming. The Gates-founded group has about $1 billion in private funding and a reported $2 billion from the government supporting the project.  

TerraPower CEO Chris Levesque told the Financial Times the plant could begin construction in June and enter commercial operation in 2030. 

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FERC Upholds De-pancaking Provisions in LG&E/KU Rates

FERC on March 21 upheld its May 2023 order reinstituting de-pancaking provisions in Louisville Gas & Electric and Kentucky Utilities’ transmission rates, which the utility has challenged before the D.C. Circuit Court of Appeals (ER23-2656-001, et al.). 

The commission’s May 2023 order reversed its 2019 decision allowing the company to remove provisions that de-pancaked its rates as a condition of LG&E/KU’s 2006 withdrawal from MISO, ensuring customers wouldn’t pay duplicate rates across the merged company’s territory. 

FERC’s reversal followed a D.C. Circuit order remanding the 2019 decision back to the commission after several municipal utilities in Kentucky sued. 

Upon reconsideration, FERC decided that removing the de-pancaking mitigation “will have an adverse effect on rates for the customers involved.” It directed LG&E/KU to reinstitute the provisions, retroactive to March 2021. 

LG&E/KU complied, but not without protest. It filed both its new de-pancaked rates (Rate Schedule 525) and a request for rehearing of the order on remand. FERC in November found that the utility had only partially complied with its directive, as it had not fully restored the provisions of its pre-2019 rates (Rate Schedule 402). The utility also requested rehearing of this order. 

FERC automatically rejected the utility’s rehearing request after not acting within 30 days. The order issued at the commission’s March 21 open meeting rejected the utility’s arguments as out of time: FERC found that it raised issues that should have been in response to the order on remand, not to the order on the company’s compliance filing. 

“LG&E and KU’s substantive arguments, however numerous or illustrative, go beyond compliance with the remand order’s directive,” FERC said. “Further, contrary to LG&E and KU’s argument that this compliance filing was the first opportunity to address the justness and reasonableness of RS 525, LG&E and KU had a full opportunity to raise arguments supporting their request to end de-pancaking mitigation in the proceedings leading to the remand order, as well as raise arguments concerning the remand order’s compliance directive to reinstitute the de-pancaking provisions of former RS 402, now found in RS 525, in their subsequent request for rehearing of the remand order.” 

FERC also issued a letter order March 21 approving the utility’s revisions to RS 525 (ER23-2656-002). 

LG&E/KU will now take its arguments to the D.C. Circuit, where it filed a petition of review over FERC’s 2023 order in February. 

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Deregulation Drove 25 Years of Innovation, IPPNY Panelists Say

ALBANY, N.Y. — New York’s transition to a deregulated wholesale power market helped drive the state’s adoption of innovative energy technology and policies, panelists said March 19 at the Independent Power Producers of New York’s 38th spring conference 

“We’ve seen a transformation in front of our eyes,” said FERC Chair Willie Phillips. 

IPPNY President Gavin Donohue also celebrated the 25th anniversary of New York’s market deregulation, highlighting the state’s achievements in reducing greenhouse gas emissions, transforming its energy investment strategies and taking the cost burden of transmission development from “the backs of ratepayers.” 

According to IPPNY, energy market deregulation has kept wholesale electricity costs below inflation rates, halved carbon emissions, reduced sulfur dioxide and nitrogen oxide emissions by over 90% each, and spurred billions of dollars in grid investments by independent power producers. 

IPPNY President Gavin Donohue | © RTO Insider LLC

However, Phillips said the state and country face new challenges, noting that, after years of flat demand, electricity use is spiking due to large load facilities such as microchip manufacturing plants and the energy-intensive data centers required for artificial intelligence computing. 

“We’ve seen demand increase in a way we didn’t expect,” he said, “and this means, after being flat for the past decade, New York is grappling with how to bring new resources on to match the demands our system and also, at the same time, transition to a clean, more renewable energy future.”  

Phillips said this is “the background we come to this conference with, as we talk about and celebrate the 25th anniversary of [New York’s] market.”  

Reflecting on 25 Years, Looking Ahead to 25 More

NYISO, approved by FERC in 1998 as the New York Power Pool’s successor, initiated its competitive electricity markets on Dec. 1, 1999, and initially oversaw a transmission grid spanning over 10,700 miles powered almost entirely by fossil fuels, according to the New York State Energy Research and Development Authority.  

“When we started to work on setting up market rules for competitive markets, we were primarily interested in creating the nuts and bolts of a competitive market: efficiency, lower costs and innovation,” said Suedeen Kelly, a partner at Jenner & Block and former FERC commissioner. “And it worked, and it’s continued.” 

The ISO now manages over 11,000 miles of transmission, according to its 2023 Gold Book, and operates a system increasingly supported by a diverse group of resources such as solar or wind. 

Suedeen Kelly, Jenner & Block | © RTO Insider LLC

Saying that regulators appreciate how “New York takes risks,” Kelly praised the state for both adapting to evolving challenges and striving to incorporate new technologies into its market.  

IPPNY estimates New York’s generation fleet has grown from 28 GW in 1999 to about 41 GW today. However, according to NYISO’s 20-year outlook, to meet its Climate Leadership and Community Protection Act (CLCPA) obligations, the state will need between 111 and 124 GW of installed capacity by 2040, with at least 95 GW of this coming from a blend of intermittent, energy storage and dispatchable emissions-free resources. (See “NYISO Releases the Outlook,” NYISO OC Discusses NOPR Comments, High Temps, EDS Results.) 

Following the CLCPA’s ambitious decarbonization goals — 70% renewable electricity by 2030, 100% zero-emission electricity by 2040 and net-zero emissions statewide by 2050 — New York has adopted a more proactive legislative strategy, focused on promoting clean energy, retiring fossil fuel plants and expanding transmission. 

“Everything in our industry is changing,” said Phillips, in response to a question raised by Donohue about how regulatory frameworks must adapt to future challenges like climate change and more energy-progressive policies. 

“We as regulators have to change the way we approach these issues,” he added, “and we need a new generation to think differently about these problems.” 

However, 25 years ago, this way of thinking would have been anathema to many New York legislators and regulators. 

“That’s not the case anymore,” said William Flynn, industry team leader at law firm Harris Beach and a former PSC chair. 

William Flynn, Harris Beach | © RTO Insider LLC

“Now, another branch of government is actively involved in shaping the future of the energy sector, which obviously impacts the future of competitive markets” he said, “but, no stone should be left unturned if we want to be truly successful in taking competitive markets to the next level.” 

New York policymakers and agencies now aggressively seek to cut GHG emissions, invest in transmission buildout and resilience, and develop net-zero resources to replace an aging fossil fuel fleet, a marked shift in policy thinking made possible by market deregulation, according to IPPNY panelists. 

Case in point, according to the New York Department of Environmental Conservation, which reports the state’s decarbonization progress annually, statewide GHG emissions in 2021 were 10.2% below the baseline limit adopted by the CLCPA’s regulations, with the energy sector’s emissions in 2021 being 19% lower than in 1990 but still accounting for about 76% of the state’s total emissions. 

However, the Legislature is likely to accelerate the state’s decarbonization efforts as it considers bills like the NY HEAT Act (S2016A), which would eliminate the 100-foot rule requiring gas be provided to new customers, or another that expands New York’s hydraulic fracking ban by prohibiting carbon dioxide in natural gas extraction (S8357). 

‘Magic’ in the Transition

In his keynote, PSC Chair Rory Christian reflected on the commission’s evolution after deregulation and how it can now harness the “magic” of new advanced technologies to address CLCPA mandates and tackle today’s challenges.  

“While we can understand and marvel about the technology we all possess,” he said, “one thing I think most people don’t take into consideration, however, is the fact that our ability to wield this magic is defined by the availability of cheap, reliable, safe energy systems, and that our daily lives depend on our ability to wield this magic.” 

Christian said New York’s “departure from a vertically integrated utility model to a restructured wholesale electric market” set the stage for the PSC to support the CLCPA’s net-zero goals, since it allowed the commission to incorporate competition into the state’s energy markets, mitigating financial risks to ratepayers by shifting development costs to private entities. 

“New York utilities have either maintained or improved their reliability and have done so while weathering increasingly severe and frequent climate events,” he said, adding that the PSC, which oversees the state’s utilities, “works tirelessly to identify the pathways to address the state’s future energy needs and ensure an equitable access to energy.” 

“We recognize that our actions have impact on lives and livelihoods, and that our actions mean the difference between our security and calamity, and the ripple effects can extend far beyond our state borders,” he added. 

Christian said that for New York to “remain ahead of the curve,” the PSC remains committed to adapting to looming challenges, including electrification, modern technologies like AI and climate change, since the commission must provide New York and its utilities with the capacity to successfully adapt.  

He detailed how the PSC has sought to help New York achieve the CLCPA’s mandates by opening a new proceeding to investigate modern resources or technologies, engaging state utilities to coordinate their grid planning processes, approving bulk and local transmission system investments, and creating competitive procurement processes to address the state energy system’s changing needs. 

“We in New York, and across the U.S., must be prepared to capture these prospective benefits and provide the power needed to harness this new form of magic,” he said, “and what’s clear to me, is that [New York’s] competitive markets will likely play a role in each.” 

New York is walking a fine line between its lofty aspirations and realities on the ground, but as was similarly expressed at last year’s IPPNY conference, industry stakeholders are keen to take advantage of the new opportunities that will come from the state’s pursuit of a decarbonized economy and cleaner grid. (See IPPNY Panelists Urge Collaboration, Coordination in Transition; Overheard at IPPNY 2023 Spring Conference.) 

This delicate balance was summarized by Donohue in his closing remarks. 

While he attributed the success of New York’s decarbonization efforts to advantages gained from the transition to a deregulated market, he pointed out that, despite those accomplishments, “there’s a lot of work left to be done in New York, since we still have to come up with an awful lot of zero-emission resources.” 

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PJM MRC/MC Briefs: March 20, 2024

Stakeholders Reject Changes to EE Measurement, Verification 

VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee rejected four proposals to revise how the RTO determines how much capacity energy efficiency programs can enter into the capacity market. (See “PJM MIC Briefs: March 6, 2024.) 

The proposals were built off the package PJM brought to the MRC in February, which sought to delineate the boundary between the two baselines against which EE providers can measure the savings from more efficient equipment and tighten qualifications for the baseline load, which tends to yield higher calculated savings than the standard baseline. 

The PJM proposal received 51% sector-weighted support, short of the two-thirds threshold required. A proposal from Vistra Energy received 66.5% support, an alternative from CPower carried 38% support and another from Affirmed Energy had 31.5% support. 

The PJM proposal would have required, among other changes, that EE providers have a contract with each individual end user, demonstrate that certain more efficient equipment would not otherwise have been installed, and account for any “leakage” of EE products purchased in one region but installed in another. 

Affirmed Energy and CPower both brought alternate proposals they argued would not significantly impact EE participation in the capacity auction while still meeting PJM’s goal of enhancing measurement and verification of that capacity. 

The Affirmed proposal focused on the impact to mid- and upstream EE programs, which seek to encourage retailers and manufacturers to offer more efficient products and share those products’ capacity market savings. Capturing savings at the retail level allows for small purchases to add up to the 100-kW threshold for EE participation in the wholesale market, a scale small residential consumers are unlikely to meet, Affirmed’s Luke Fishback said. 

Fishback said PJM’s data collection requirements would require EE providers to receive consumer data for each retail EE product customer and enter a contract with each to obtain sole rights to enter those savings into the capacity market, which he argued would not be feasible and would eliminate much of that market’s aggregation. 

The CPower proposal targeted PJM’s causation requirement for EE to qualify for the baseline load, which would have required that customers install equipment specifically to receive capacity market revenues. Senior Vice President Kenneth Schisler argued this would disqualify projects with multiple consumer benefits, such as home renovations improving insulation that may also be damaged by humidity. 

The CPower proposal would have replaced PJM’s language stipulating that a project “would not have occurred absent participation in the wholesale market” with the need for “a direct connection to participation in the wholesale market.” 

Both alternatives also took issue with PJM’s proposal that state technical reference manuals used to measure EE savings under the baseline load must be less than three years old. The Affirmed proposal would shift that to six years, and the CPower proposal to five. 

Fishback said most TRMs issued by PJM states would have been invalidated under PJM’s proposal, requiring EE providers to instead study meter data, which he said would take too long to complete for the 2025/26 Base Residual Auction (BRA). 

After the committee rejected the three proposals, Vistra offered a fourth revising PJM’s proposal to include a transitional period for the TRM limitations. Manuals less than five years old would be permitted for the 2025/26 BRA, four years for the following, and three years for 2027/28 and onwards. 

Revised Reserve Requirement Study Values Endorsed

Stakeholders endorsed revised installed reserve margin (IRM) and forecast pool requirement (FPR) values accounting for inputs that changed following FERC’s approval of PJM’s critical issue fast path (CIFP) filing reworking its approach to risk modeling and accreditation. The new values were endorsed with 88% support at the MRC and passed by acclamation at the MC on March 20. (See FERC Approves 1st PJM Proposal out of CIFP.) 

PJM’s Patricio Rocha Garrido said the need to recalculate was driven by several analytical developments since figures were approved by the committee in October and by fine-tuning made in recent months, as well as by parameters updated to better reflect resource pool changes. (See “Stakeholders Endorse Revised RRS Values,” PJM PC/TEAC Briefs: Feb. 6, 2024.) 

The revised figures raise the IRM to 17.8%, an increase from 17.7% in the 2023 Reserve Requirement Study (RRS) results endorsed in October. The FPR would decrease to 0.9387, down from 1.1165 in the October values. 

The Planning Committee voted in February to reset the two values, moving the figures in a similar direction to that endorsed by the MRC last week. The PC endorsed an IRM of 17.7% and an FPR of 0.9440. 

Several resources that had submitted a notice of intent to offer into the capacity market were removed from the resource mix after PJM determined they are unlikely to come online prior to the start of the delivery year. Deactivations that were recently announced or not included in the original analysis were also removed from the expected available generation. 

PJM and its Independent Market Monitor found that the characteristics of some resources had changed enough to warrant reclassifying their effective load carrying capability (ELCC) class. One of the prime reasons for this was a generator being reconfigured to run on a different fuel. 

Some resources were also identified as having incorrect installed capacity (ICAP) values, particularly pseudo-tied generation, and some that had ambient derate tickets with variable megawatt reductions did not have the variability captured in their data. 

MRC Amends Large Load Adjustment Forecast Issue Charge

The committee voted to revise an issue charge framing ongoing stakeholder discussion of how capacity assignments from forecasted large load additions are assigned to market participants in the same transmission zone. The proposal expands the scope of the discussion to consider load-serving entities (LSEs) able to control large load addition (LLAs) forecasts in their region. (See “1st Read of Proposal on Capacity Obligations Resulting from Large Load Additions,” PJM MIC Briefs: March 6, 2024.) 

Mike Cocco of the Old Dominion Electric Cooperative (ODEC) said the unrevised language could grant sole control over the ability to submit forecasts to electric distribution companies (EDCs), including for any LSEs within their footprint. He argued that allowing a market participant to affect another participant’s load forecast is contrary to PJM’s basic market principles. 

Joshua Burkholder of American Electric Power (AEP) said he supported the amendment as a minor clarification and improvement to the issue charge, noting that AEP was one of the document’s co-sponsors. 

Dominion’s Jim Davis, the other co-sponsor, said the proposal being considered by the Market Implementation Committee will reflect some of the clarifications in the issue charge. 

The proposal would exclude LLAs from the calculation of base zonal scaling factors and apply that load to the obligation peak load of the zone it is projected to be added to. LLAs are determined by PJM using information from LSEs about expected load growth and are detailed in the RTO’s annual load forecast reports under Table B-9. 

Calpine Proposes Changes to Dual Fuel Classification

Calpine’s David “Scarp” Scarpignato presented a quick-fix proposal expanding the definition of dual-fuel resources to include units that start using their primary fuel and operate on secondary fuel. He said some gas-fired resources can start multiple times on the fuel present in the portion of pipeline leading to the generator, even if the pipeline feeding into that segment is offline or the generation owner has not entered a fuel contract. The quick-fix process allows for a problem statement and issue charge to be brought concurrent with a proposed solution. 

The proposal would revise the Manual 34 definitions of dual-fuel combined-cycle and combustion turbine resources to require that they be capable of starting independently using “behind-the-fuel meter source” and then operate on the secondary fuel. 

First Read on PJM Regional Planning Proposal

PJM’s Michael Herman presented a first read of the RTO’s proposal to create new long-term regional planning scenarios informing the development of the Regional Transmission Expansion Plan and state initiatives through the State Agreement Approach (SAA). (See “Stakeholders Long-term Regional Transmission Planning Proposal,” PJM PC/TEAC Briefs: March 5, 2024.) 

The proposal would add five new scenarios: two base cases focused on reliability needs eight and 15 years out; two policy scenarios looking at new entry backed by state legislation eight to 15 years in advance; and an additional policy scenario including higher generation entry not backed by signed legislation. The two-year planning cycle would be extended to three years because of the increased number of scenarios. PJM’s current 10-year voltage analysis would be performed on the eight-year base scenario and include thermal analysis. 

Herman said the scenarios are designed to capture evolutions the grid is expected to undergo over the next 15 years, namely 44 GW of load growth, 30 GW of generation deactivations and increased renewable energy penetration. 

Ryann Reagan, of the New Jersey Board of Public Utilities (NJ BPU), said the new paradigm would provide the PJM planning team with a valuable new tool and that could aid other states follow NJ’s lead with using the SAA to pursue clean energy objectives. 

Governing Documents Revisions Endorsed Through GDECS Process

Several changes to PJM’s governing documents were endorsed by the committee in line with the recommendations made by the Governing Document Enhancement and Clarification Subcommittee (GDECS). The revisions were approved by acclamation with no objections and several abstentions. (See “Other MRC Business,” PJM MRC/MC Briefs: Feb. 22, 2024.)  

PJM’s Michele Greening said terms being added to the documents’ definition sections are already defined in the existing language, but that language has not been duplicated in the definition section. 

On March 20 and during the first read of the changes at the Feb. 22 MRC meeting, several stakeholders questioned if some of the package’s recommendations exceed the inconsequential nature of revisions typically drafted through the GDECS. 

PJM also presented a first read on another set of revisions recommended by the GDECS, including a change to lowercase several references to “end-use customer” in the tariff around load management participation in the capacity market.  

PJM’s Daniel Vinnik argued the terms were capitalized through a scrivener’s error and were not meant to suggest that consumers participating in demand response programs must be PJM members.  

The second set of GDECS revisions are set to be voted on by the MRC on April 25 and the MC on May 6. 

Other Committee Business:

Consideration of a quick-fix proposal to expand the winter availability window for demand response resources was spiked to the April 25 MRC meeting to give more time for sponsors to consider continuing pursuing changes through the expedited stakeholder process. Bruce Campbell, of Campbell Energy Advisors, said the sponsors may only seek endorsement of the issue charge next month, which would open a standard stakeholder process to explore if changes to the load participating in demand response programs and market changes made through the CIFP process warrant changes to the availability window. 

PJM’s David Hauske presented a first read on a proposal revising the Operating Agreement, Tariff and manuals to add definitions of three synchronous condenser parameters — condense startup costs, condense-to-generate costs and condense energy use. He said the parameters are in use and there would be no change to PJM practices. 

Members Committee

Advocates Concerned About Transparency over Filing Rights Changes

Greg Poulos, executive director of the Consumer Advocates of PJM States presented consumer advocates’ concerns over the openness of discussions between PJM and transmission owners on revising the consolidated Transmission Owners Agreement (CTOA) to shift Federal Power Act Section 205 filing rights from PJM members to the RTO.  

Exelon Director of RTO Relations Alex Stern laid out the proposed changes to the Members Committee during its Feb. 22 meeting, where several transmission representatives noted that changes to the CTOA are made through negotiations between the Transmission Owners Agreement-Administrative Committee (TOA-AC) and the PJM Board of Managers. (See “TOs Considering Handing PJM Transmission Planning Filing Rights,” PJM MRC/MC Briefs: Feb. 22, 2024.) 

While advocates have been pushing for PJM to plan more proactively, Poulos said negotiations to expand its filing rights and other associated changes to the balance between stakeholder and RTO authority should be public. He said that transmission owners speaking during the February MC meeting argued that the changes could have benefits to consumers; however, those consumers’ representatives do not have a voice at the table where those changes are being considered. 

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FERC OKs $142M Grand Gulf Settlement with Entergy Arkansas

Entergy will pay its Arkansas affiliate $142.3 million under a settlement FERC approved March 21, the latest in the ongoing billing dispute over the utility’s Grand Gulf Nuclear Station (ER22-958, ER23-435, ER23-816, ER23-1022, ER23-1164, EL24-5). 

The company’s System Energy Resources Inc. (SERI) sells energy and capacity from the 1,443-MW nuclear plant in Port Gibson, Miss., to Entergy Arkansas and the utility’s three other operating companies under a cost-based formula rate. 

Grand Gulf’s Unit Power Sales Agreement has been the subject of complaints of overcharging by regulators in Arkansas, Louisiana, Mississippi and New Orleans since 2017. 

SERI said the new settlement is part of a $588 million deal filed in 2022. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.) 

FERC also approved a partial settlement over Grand Gulf last April. (See FERC OKs Partial Settlement in Entergy Grand Gulf Row.) 

In addition to the payment to Entergy Arkansas, the new settlement specifies that SERI will use a return on common equity of 9.65% in its monthly billings to the utility effective November 2023 and that no settling party can propose a change to the rate until at least June 30, 2026. 

SERI also agreed to use a capital structure with an equity ratio not to exceed 52%. 

The commission said the settlement was in the public interest because it was uncontested and appears to be fair and reasonable. 

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SPP Board Approves Markets+ Phase 1 Tariff

SPP’s Board of Directors approved the initial tariff for its Markets+ service offering in the Western Interconnection March 25, clearing the way for its filing at FERC. 

Board Chair John Cupparo called the action an important step, but not the last, in continuing SPP’s development of the day-ahead market. Markets+ is just one of several western expansion initiatives, which include SPP RTO West and an imbalance market. 

“We don’t know exactly what the outcome is going to be [as] SPP continues to prudently pursue this western expansion, given the long-term potential of this expansion,” he said. “Another way to say that is five, 10, 15 years from now, I wouldn’t want to be in the position of answering the question, ‘Why didn’t you pursue this?’” 

SPP is competing with CAISO’s Extended Day-ahead Market (EDAM) to attract western entities to Markets+. FERC already has approved the bulk of EDAM’s tariff, and last week, Portland General Electric and Idaho Power signaled their intent to join the CAISO market. That increases EDAM participants to five members. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM and CAISO’s EDAM Scores Key Wins in Contested Northwest.) 

SPP’s Markets+ development phases. | SPP

“Based on experience in the West, it is always a challenge to completely get our arms around what entities in the West will do and what they’ll ultimately decide,” said Cupparo, a Colorado resident with western utility experience. “We’re still entering that phase right now. There are many variables and diverse perspectives that will influence these decisions.” 

The tariff’s filing will complete the first phase of the Markets+ development. SPP lists 38 western entities as having participated in drafting the tariff and its protocols. 

The grid operator hopes to receive FERC approval by year’s end. In the meantime, SPP and interested participants will develop and negotiate funding agreements for the second phase. SPP will file at FERC a financing approach, projected to be about $140 million plus financing costs. 

Once FERC has approved the tariff, SPP will begin acquiring and modifying the necessary software, hardware and related processes. Phase 2 work will begin next year after the financing approach is approved. 

“I think we’re probably several years away from parties participating in Markets+ and deciding that they’ve gotten comfortable with the regionalization to the level where they’re now interested in pursuing an RTO,” said Antoine Lucas, SPP’s vice president of markets. 

The motion to approve the tariff cleared the Members Committee’s advisory vote, 15-1, with four abstentions. The Natural Resources Defense Council’s Christy Walsh cast the lone dissenting vote over concerns the tariff isn’t complete. 

Markets+ stakeholders and SPP staff have been working together since last year putting together the tariff’s various pieces. The Markets+ Participants Executive Committee has held 86 votes on tariff language since August, with an average approval rating of 97.72%. Several identified tariff elements were postponed because of the time necessary to resolve them. 

Lucas reminded members the tariff they were voting on does not include the second phase. That will include contractual obligations that set cost recovery and financial obligations associated with the market’s implementation. 

“This being a standalone service, the funding for that service will be taken care of by the participants in the process itself,” he said. 

CFO Sterzing Resigns

SPP CEO Barbara Sugg announced during a break in the call that Deborah Sterzing submitted her resignation March 22 as the grid operator’s chief financial officer. 

“We hate to see her go. We certainly wish her well in her continued career within our industry,” Sugg said. 

David Kelley, vice president of engineering, has been appointed interim chief financial officer. He is already involved in several financial activities for SPP, Sugg said. 

Sterzing joined SPP in February 2023. She replaced longtime CFO Tom Dunn, who retired in 2022 after 21 years at the financial helm. 

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NE Energy Officials Stress the Need for Dispatchable Resources

As intermittent renewables proliferate in New England, the region must do a better job incentivizing reliable, dispatchable resources that can support the grid as it decarbonizes, speakers at Raab Associates’ New England Electricity Restructuring Roundtable emphasized March 22.  

“We cannot remove conventional generation before we stand up its replacement,” said Charles Dickerson, CEO of the Northeast Power Coordinating Council, adding the region will face shortfalls if it fails to heed this warning. 

“The more renewables we have, the more I get prickly around adequacy,” Dickerson added. “It’s not how much is there; it’s how much is there when you need it.” 

Gordon van Welie, CEO of ISO-NE, said the RTO’s ongoing efforts to reform its capacity market should help New England more efficiently ensure resource adequacy, but added that more changes likely are needed to align the region’s wholesale electricity markets with the clean energy transition. (See ISO-NE Moving Forward with Prompt, Seasonal Capacity Market Design.) 

“I can’t miss the opportunity to make a pitch about carbon prices,” said van Welie, who has long expressed support for the concept but has indicated ISO-NE would need support from all New England states to proceed. (See ISO-NE: States Must Lead on Carbon Pricing.) 

Van Welie said the RTO anticipates increasing renewable energy will reduce revenues from the energy market, requiring more money to come from the capacity market and state-led power purchasing agreements. A carbon price could help prevent an over-reliance on the capacity market and PPAs, van Welie said. 

“You’d tax the carbon emissions at source, put that into the offer price, but then you would rebate the money that you’re collecting from those carbon emissions directly back to load at the wholesale level, so you’d mitigate the price impact,” van Welie added. He called the mechanism “an elegant way of trying to balance the consumer impact with the incentives needed to drive the thing you want, which is to reduce carbon emissions.” 

Dickerson noted that inverter-based resources also bring new challenges related to ride-through capabilities and cybersecurity threats, and that standardization is needed to ensure resources meet the technical requirements needed for grid reliability.  

“We’ve had no less than five or six episodes across the country where an inverter-based resource may have tripped offline because of what we can call a normal blip,” Dickerson said. “Not only did that particular inverter-based resource come offline, it took all the inverter-based resources offline that were connected to it. That’s unsustainable.” 

While Dickerson stressed that the risks associated with inverter-based resources have already arrived, van Welie said the Eastern Interconnection likely is “fine for the next five years,” with problems likely emerging “around 10 years out.” 

Batteries can use synthetic inertia to help mitigate the loss of spinning thermal resources, “but the inverters need to be designed to do it,” van Welie said, adding this will likely require some type of regulation.   

Commissioner Katie Dykes of the Connecticut Department of Energy and Environmental Protection acknowledged the need to ensure grid reliability as the resource mix changes but said the region must continue to accelerate the deployment of clean energy. 

“We really have to scale up all our efforts in regards to clean energy if we’re going to achieve our goals,” Dykes said.  

Dykes said carbon pricing is “an important tool,” but added it’s “just one tool, and we need a number of different tools in order to see the new entry coming in that can maintain reliability at a rate that ratepayers can afford.” 

Dykes added that future procurements could extend to developing generation technologies like advanced nuclear, geothermal and hydrogen fuel cells. She said she’s heard from developers that investing in advanced nuclear projects makes little sense in restructured markets compared to vertically integrated markets. 

“We can’t afford to take those types of things off the table,” Dykes said. “We have to figure out how to accommodate them.” 

The commissioner highlighted the efforts of Connecticut, Massachusetts and Rhode Island to coordinate offshore wind procurements — bids are due for all three states March 27, with the winning bids to be selected in August. (See New England States Delay Offshore Wind Solicitations.) 

Dykes called the coordinated procurement “a template for multistate coordination,” while advocating “predictable, regular auctions” going forward. 

“We’re in a moment of extraordinary collaboration,” Dykes said. “That’s what gives me encouragement.” 

Liz Anderson, chief of the Energy and Ratepayer Advocacy Division at the Massachusetts Attorney General’s Office, stressed the need to keep ratepayer interests front and center. Anderson said the region should consider the cumulative impacts of programs and investments on electricity costs when designing programs, noting that skyrocketing costs will hinder the clean energy transition. 

“A lot of conversations are happening in silos,” Anderson said. “We need to start thinking more holistically about all these costs together.” 

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‘Converting to EVs not Sufficient’ to Reach Climate Goals

WASHINGTON ― Working at a state transportation department used to be pretty humdrum, according to Tim Sexton, who started his career at the Department of Transportation in Washington state.  

“Transportation used to be departments of highways or departments of roads,” said Sexton, who now is assistant commissioner for sustainability, planning and program management at Minnesota’s DOT. “Now you have some states … saying, ‘You know, we can do more,’ and what we’re saying is, anything that touches transportation, and especially transportation and climate, we want to have a role in and want to try to lead on … and it’s partly out of self-initiative, but also partly because our hand is being forced.” 

Sexton was one of four panelists speaking about how to build clean, sustainable transportation systems, at the 2nd Annual U.S. Tech for Climate Action Conference. The conference’s tech focus notwithstanding, the transportation panel was less concerned with specific technologies and more interested in digging into the research, policies and public-private partnerships needed to ensure access to clean, convenient mobility across a broad range of urban and rural environments.  

“As we start to look at state goals for decarbonizing the economy, transportation plays a role” as a top emitter of greenhouse gases at both national and state levels, Sexton said of Minnesota’s more holistic approach. “We look at this as a three-legged stool of vehicles, operations and fuels. A low-carbon fuel standard … could be a big part of the solution, too, so let’s get involved with that.” 

The Minnesota DOT also has waded into the politically sensitive topic of locating transmission along existing transportation rights-of-way, Sexton said. “The biggest obstacle to transmission is property rights, and if you have linear corridors that mirror our highways, that could really facilitate a lot of transmission,” he said. “How do we support that in a way that balances competing needs?” 

Colin Tetreault, senior manager for climate change and sustainability services at EY, formerly Ernst & Young, agreed that the past 10 to 15 years have seen “a better understanding of an evolutionary thesis of what we’re solving for.” 

“We used to think about kind of single-passenger conveyance, or how do we move a car from point A to point B,” Tetreault said. “That model [and that] decision calculus [is] changing … to how do we move goods, ideas, people and services safely, effectively, affordably, efficiently and equitably?” 

The equity and environmental justice focus in transportation policy also is a major change, he said. “When you think about access to food, to health, to education, it is a … travesty that people do not have good access to transport and what that does to hinder community- and state-level growth. … These things don’t exist in a vacuum because they are layered together,” he said.  

“Converting to EVs is not sufficient … to get us to net zero by 2050,” said Gretchen Goldman, director of climate change research and technology at the Department of Transportation, referring to President Joe Biden’s goal for economywide decarbonization. “And so that means also investing in transit … and really making sure that we’re diversifying in mode choice in lots of ways.” 

A priority for DOT is focusing on different contexts and different communities, and how to apply new technologies “because it’s not going to be the same as what it looks like in urban spaces and similarly on tribal nations and lands.” 

Greening Rideshares in NYC

In New York City, combining transportation equity and decarbonization has meant looking closely “at modes of transportation that are used on a day-to-day basis in everyday lives of New Yorkers, but are simultaneously modes of transportation that we have control over,” said Isabelle Thomas, policy adviser for living streets and public spaces. 

Exhibit A, Thomas said, is the Green Rides Initiative, which has set a target for all vehicles in the city’s rideshare fleet ― taxis, Ubers and Lyfts ― to be either zero emission or wheelchair accessible by 2030. For 2024, 5% of “all high-volume for-hire trips” will have to be zero-emission or wheelchair accessible, rising to 15% in 2025 and 25% in 2026 and then increasing by 20% per year to reach 100% by the end of the decade, according to a city website. 

Overseen by the city’s Taxi and Limousine Commission, the initiative means “we’ve already taken care of a part of what is a 78,000-vehicle fleet that’s on our streets every day,” Thomas said. 

NYC also is working on electrifying its school bus fleet by 2035, drawing on a combination of state and federal funds, Thomas said. On March 18, Mayor Eric Adams announced New York City had received $61.1 million in federal funds from the Infrastructure Investment and Jobs Act, which would be used to buy 180 new electric school buses (ESBs), quadrupling the total number of ESBs in the city’s fleet. 

An additional $15 million from the U.S. DOT will go toward a “freight-focused” electric truck and vehicle charging depot to be located in the Hunts Point Food Distribution Center, one of the state’s busiest trucking hubs, according to the announcement’s press release.

Another key component of NYC’s strategy for transportation decarbonization, Thomas said, is ensuring all New Yorkers can find DC fast chargers within 2.5 miles of where they live or work.

Building a Used EV Market

Consumer engagement was a major factor for Minnesota’s adoption of California’s Advanced Clean Cars II (ACCII) rule, which requires that all new light-duty vehicles sold in the state be zero emission by 2035. 

“We went around the state and everybody said, ‘We should have more electric vehicles in the state, but we can’t get them here. [We] have to go to another state because of where we are in the middle of the country.’ You had to go quite a way to get an electric vehicle,” Sexton said. 

According to Conservation Minnesota, a nonprofit advocacy group, only about half the models of EVs available on the market are for sale in the state. 

Public health and equity also were drivers for ACCII, Sexton said, “If we don’t have vehicles coming into the state, especially new vehicles, we’re not going to have a used vehicle market either, and without that used vehicle market, not everyone is going to be able to get into an EV.” 

Sexton also talked about Minnesota’s approach to transmission siting along highway rights-of-way, working with a group called NextGen Highways to look at the opportunities and challenges. To begin with, rights-of-way are a “constrained resource,” he said. “There [are] not unlimited amounts of it. … 

“There’s a lot of stuff buried alongside the road and underneath it, whether it’s water, sewer, fiber,” which requires “being really thoughtful about when, how [and] where are we allowed to access” these sites, Sexton said. Permitting these projects means making sure “you have evaluated all the options, and this is the best path,” he said.

According to a 2022 NextGen feasibility study, undergrounding HVDC and broadband lines in highway rights-of-way could help prepare Minnesota’s grid for transportation electrification ― and the installation of DC fast chargers ― while increasing opportunities for remote work, online learning and other online services. The result could be an overall decrease in vehicle miles traveled in the state, the report says. 

Sexton sees potential in linking reduction of vehicle miles traveled to rethinking and reform of land use, such as making communities more pedestrian and bicycle friendly. “I don’t know if I want to live in a community [where] everybody has a car and everybody is driving and spending two hours one way to get to work,” he said. “Even if it’s not polluting, is that the way you want to live?” 

Going Further, Faster

While providing unprecedented funding for a range of decarbonization initiatives, the IIJA and Inflation Reduction Act have posed challenges for state government agencies that have to interpret and implement the new programs. But, Sexton said, the direction coming from federal agencies is as important as, if not more important than, the money. 

Panelists generally agreed that cross-agency and cross-stakeholder input and planning are essential parts of designing and implementing effective, successful programs. Tetreault favors working with regional economic development agencies, rather than industry trade groups.  

Economic development agencies are more likely to look at “smart, equitable, clean and green jobs … [as] a growth vertical. Latching onto that in order to indicate there’s economic prosperity coupled with decarbonization tied to things like transportation, I think, carries a message further,” he said. 

Minnesota has formed a Sustainable Transportation Advisory Committee, which includes regional development agencies, state and local government officials, and some of these agencies’ strongest critics, Sexton said. “We made the commitment that we would respond, not that we’d accept every recommendation, but we’d facilitate the conversations,” he said. 

At the same time, Tetreault also stressed the importance of regulatory certainty for driving capital to specific markets, regardless of federal incentives. The best policies provide both carrots and sticks, he said. “Capital will follow certainty. It will stay where it’s treated well. [It] will continue to grow where it feels warm.” 

In the face of the coming elections and potential regulatory changes, public-private partnerships could provide a way to use existing policy with capital, and provide a broader range of creative financing options, he said. State and sub-state contracts could include “things like disclosure [and] environmental performance standards,” he said.  

“Providing a vector for the capital markets to have verifiable opportunities and then to keep [them] verifiable through good disclosure management systems … we can align public and private for quick reaction,” he said. “Working together, we go further, and we go faster.” 

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DOE Study Adds to Case for Interregional Offshore Grid

An interregional transmission network for the East Coast’s offshore wind could produce almost $1.6 billion annually in generation savings and improved reliability versus radial lines, according to a study released by the U.S. Department of Energy last week. 

The Atlantic Offshore Wind Transmission Study calculated substation and cable costs for a 2050 “low-carbon” scenario with 85 GW of offshore wind from Maine to South Carolina. The analysis considered four offshore transmission topologies against a reference case using radial lines for each project with no links between offshore platforms:  

    • an intraregional topology with connections within regions;  
    • an interregional topology connecting diverse regions;  
    • an inter-intra topology combining the links in the interregional and intraregional topologies; and  
    • a backbone grid that adding interregional plan an additional cable running from Maine to South Carolina. 

The analysis, by researchers from the National Renewable Energy Laboratory and the Pacific Northwest National Laboratory, found that each of the four networked topologies had higher benefits than costs and that the interregional plan produces the highest benefit-to-cost ratio and total net value. 

Networking offshore transmission would reduce offshore wind curtailments (1 to 2 percentage points below the radial topology) and the use of higher-cost generators, DOE said. It would also increase reliability by providing alternatives during outages of other transmission lines or generation, particularly during winter peak conditions.  

“In modeled estimates using the radial topology in 2050, price differences between suitable POIs for offshore wind averaged over $100/MWh,” the report said. “This price difference is higher than the average wholesale electricity prices in recent years in some Atlantic market regions. High price differences indicate that offshore transmission with interlinking platforms can consistently flow power from lower- to higher-price regions to benefit electricity consumers by reducing the costs of generating electricity.” 

Intraregional, interregional, and backbone transmission topologies | National Renewable Energy Laboratory

The researchers’ modeling of the networked transmission showed that flows on all interlinks go both directions every season, with an average utilization rate of 50 to 60% of the available capacity on each line.  An interregional grid with a 14,000-MW capacity could displace up to 4,700 MW of firm generation capacity, the researchers said. 

The base radial plan is estimated to cost $96.3 billion. The interregional grid would add $11.4 billion in capital costs, with annualized capital and operations and maintenance costs of $840 million. But DOE said it would produce benefits of $2.4 billion annually, a benefit-to-cost ratio of 2.9. 

The backbone topology provides the second-largest ratio of 2.7, with annualized costs of $1.47 billion and benefits of $3.9 billion per year.  

The analysis envisions building offshore transmission in phases to reduce development risk and assumes the first offshore wind projects would be connected to the grid with individual radial lines. But researchers said, “early implementation of high-voltage direct current (HVDC) technology standards is essential for future interoperability.” 

The only potential negative identified by researchers: Offshore wind could be vulnerable to extreme weather in the ocean and at landing points. 

DOE’s report adds to earlier research on the benefits of a planned Atlantic offshore grid, including a 2023 Brattle study that estimated coordinated transmission planning could produce at least $20 billion in transmission-related cost savings, 60 to 70% fewer shore crossings and a reduction of about 50% in marine transmission cables (2,000 fewer miles) on the seabed. (See OSW Transmission Planning Must be Interregional, Networked and Start Now.) 

Implementation Steps

DOE’s study was accompanied by an action plan from DOE’s Grid Deployment Office that identifies the steps researchers said would be required to implement the transmission buildout. It calls for establishing collaborative bodies spanning the Atlantic Coast this year to plan transmission and cost allocation during the second half of the decade. 

It encourages RTOs and other transmission providers to simultaneously evaluate multiple benefits beyond reliability or production cost savings.  

In its transmission planning and cost allocation rulemaking, which FERC is expected to finalize this year, the commission proposed developing long-term scenarios for use in regional planning, with an increased role for states in facility selection and cost allocation. FERC has also proposed a minimum set of benefit categories with methods to quantify them (RM21-17). (See FERC Watchers Weigh in as Transmission Rule Approaches Finish Line.) 

Among the “Immediate Actions Before 2025” in the action plan is voluntary cost-allocation assignments. “Transmission cost allocation is a notoriously thorny issue that is intensified by the scale of projects and large price tags associated with interconnecting offshore wind,” DOE said. “In fact, the Business Network for Offshore Wind [recently renamed the Oceantic Network] described the issue of who pays as ‘the hardest single problem for transmission.’” 

‘Most Thorough Analysis’ to Date

DOE called its two-year study the most thorough analysis to date of options to bring the East Coast’s wind energy — projected to be a key part of the region’s decarbonization — ashore. 

The study focused on the offshore region between Maine and South Carolina and the onshore grid in those states, plus Vermont and Pennsylvania due to their proximity to the Atlantic. The 85-GW scenario for 2050 projects 27 GW of OSW injection into ISO-NE; 19 GW into NYISO, 26 GW into PJM and North Carolina, and 13 GW into the SERC Reliability Corp. region in North Carolina and South Carolina. Offshore wind would represent more than 20% of generation in NYISO and PJM and more than 40% in ISO-NE. 

The report identifies potential transmission corridors considering environmental concerns and other uses such as military zones and shipping channels. The researchers cautioned that their analysis did not have the level of detail of interconnection studies and was not intended to prescribe exact injection points.