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November 18, 2024

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ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points

Relocating two offshore wind points of interconnection (POIs) from Maine to Massachusetts could substantially reduce New England’s transmission upgrade cost requirements in the coming decades, ISO-NE told its Planning Advisory Committee on April 18. 

Shifting the points of interconnection would decrease the need for north-to-south transmission upgrades, cutting the overall cost range for transmission upgrades to $19 billion to $22 billion by 2050 compared to the original $22 billion to $26 billion estimate from ISO-NE’s 2050 Transmission Study. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.) 

“Location of offshore wind POIs are important, and results can vary significantly based on these locational choices,” said Liam Durkin of ISO-NE. “The offshore wind POI screening analysis will be one important step towards refining assumptions around offshore wind POIs.”  

The analysis used the same methodology as the 2050 Transmission study, shifting just two of the POIs in the study. One of the key findings of the original study was the need for increased transmission capacity from northern New England to the Boston area.  

Moving the two POIs south would reduce flows along the Maine-New Hampshire interface and the North-South interface in the winter, while the shifts would minimally impact summer flows, ISO-NE found. 

The lack of summer effects stemmed partly from ISO-NE’s expectation that offshore wind output would decline significantly during the summer. 

The 2050 Transmission Study considered four pathways to meet the transmission needs: an AC road map, a DC road map, an offshore grid road map and a plan focused on minimizing the need for new lines by upgrading existing infrastructure.  

The POI analysis showed that shifting the two offshore wind interconnections would benefit all four pathways, saving the AC road map an estimated $2.2 billion, the DC road map an estimated $4 billion and the offshore grid road map an estimated $2.6 billion. 

While ISO-NE initially found it could not meet its expected 2050 peak load of 57 GW through the “minimization of new lines road map,” the RTO found the POI shifts would make this road map possible, with an estimated cost of $19.8 billion. 

Although this pathway relies the least on new lines, it still would include a few, as well as substantial line rebuilds.  

“Rebuilds alone cannot successfully serve a 57-GW winter peak load along the North-South and Boston Import interfaces,” Durkin said.  

ISO-NE projects a 57-GW winter peak but also emphasized the potential benefits of lowering the peak through demand-reduction efforts. The original analysis from the 2050 Transmission Study found that limiting the peak to 51 GW would reduce transmission costs by about $8 billion. 

The updated analysis also found benefits of the POI shift with a 51-GW winter peak; taking the interconnection changes into account, the lower peak reduced the overall cost estimate to $13 billion to $16 billion.  

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Pathways Initiative Rejected for $800K in DOE Funding

The West-Wide Governance Pathways Initiative has potentially lost a key source of financial backing after the U.S. Department of Energy rejected the group’s application for $800,000 in grants to support its initial operations. 

“The Pathways Initiative did not receive DOE funding in the last round,” Western Freedom Executive Director Kathleen Staks, co-chair of the initiative’s Launch Committee, told RTO Insider in an email April 17. “We plan to share more information and potential next steps during our [April 19] stakeholder call and [will be] happy to answer additional questions at that point.” 

The group applied for the money in January in response to a DOE Funding Opportunity Announcement (FOA), seeking two tranches of $400,000 each to be disbursed over two years. The initiative was launched last July by energy officials from five Western states to develop the framework for an independent RTO that pointedly includes California and builds on CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). (See Regulators Propose New Independent Western RTO.) 

“This funding is necessary for major Pathways support functions — development of informational materials; outreach to key stakeholders; regular convenings through virtual and in-person gatherings; and facilitation to ensure meaningful participation by those who wish to engage,” the group said in a concept paper included in the grant application. (See Western RTO Group Seeking $800K in DOE Funding.) 

The funding would be “essential to performing outreach to states and groups not yet aware of, or able to participate in, the new nonprofit independent governance entity envisioned by” the initiative’s backers and make it more accessible to a larger set of stakeholders, the paper said. 

Speaking at the Launch Committee’s last monthly update March 15, Jim Shetler, co-chair of the committee’s Priority Administrative Work Group, expressed confidence that Pathways would win the DOE funding. (See Pathways Initiative Discloses Funders, Reiterates Goals.) 

Shetler, general manager of the Balancing Authority of Northern California, said the federal money would likely arrive in June or July, possibly leaving a funding gap in late spring that would likely be covered by the group’s original budget of $570,000 needed to fund Phase 1 of the effort through the end of April. 

It’s now unclear how Phase 2 will be funded. During the March update, Shetler said the initiative had raised about $430,000 from 24 stakeholder donors to cover the initial budget, with more pledges on the way. 

As of April 17, a “pledge summary” spreadsheet maintained by the group showed the list of donors had expanded to 32. It now includes the Interwest Energy Alliance, Western Resource Advocates, Primergy Solar, Solariant Capital, Pattern Energy, Brookfield Renewable Partners, Engie North America and one “individual contributor.” But the spreadsheet shows only pledge ranges, not donors’ specific contributions. 

The denial of federal funding comes just a week after the initiative released its straw proposal for tackling a “stepwise” transition of CAISO’s WEIM and EDAM to independent governance and could represent a setback for the EDAM in its competition for participants with SPP’s Markets+. (See Western RTO Group Floats Independence Plan for EDAM, WEIM.) 

SPP officials, meeting in Denver, declined to comment on the development. 

CAISO spokesperson Anne Gonzales said the ISO would defer comment to the Launch Committee. 

Tom Kleckner contributed to this article from Denver.

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FERC OKs Pipeline Expansion Despite West Coast States’ Opposition

FERC on April 16 rejected rehearing requests on a certificate it granted to TC Energy to expand its Gas Transmission Northwest (GTN) pipeline’s capacity into the Northwest over three states’ objections and Commissioner Allison Clements’ dissent (CP22-2-001). 

The XPress project would provide 150,000 dekatherms per day of incremental firm transportation service from Idaho’s border with British Columbia to the Malin Meter Station in Klamath County, Ore., near the California state line. It has signed three deals with terms of 30-33 years for the pipeline’s entire capacity. 

While the pipeline has offtake deals with customers, California, Oregon and Washington argued that their climate policies, which require significant economywide natural gas cuts, will lower gas demand in coming decades and asked FERC to reject the proposed expansion. 

The commission mostly disagreed, finding the deals for 100% of its capacity significant evidence of need and that the project would cut costs to consumers while increasing supply diversity. 

The case covers similar arguments to a FERC-approved Transcontinental Gas Pipeline expansion, opposed by New Jersey regulators because of their state’s climate targets. That decision has been appealed to the D.C. Circuit Court of Appeals, which held oral arguments on it in March. (See FERC Approves Pipeline Expansion Despite New Jersey’s Worries.) 

The Western states argued the deals were not enough to show demand and cited another D.C. Circuit decision in Environmental Defense Fund v. FERC, in which the court rejected the commission’s approval because it had relied on a single-precedent agreement between the pipeline and an affiliate as evidence of need. 

But none of the buyers is an affiliate of GTN, nor is there evidence of self-dealing, so the EDF case does not apply, FERC said. 

“We continue to find that GTN presented sufficient evidence of project need — it executed precedent agreements for 100% of the project’s capacity with unaffiliated shippers, each for a duration of 30 or more years — notwithstanding the legislation and policies that the states argue will reduce demand,” FERC said. “These precedent agreements, as noted herein, are significant evidence of need.” 

The predictions that state climate laws will cut gas demand to make the expansion unneeded are speculative, FERC said. While the three West Coast states have climate laws, half the capacity is for Intermountain Gas, which serves customers in Idaho. 

Clements argued that GTN’s rate case offered different information on future gas demand; that FERC should have examined alternatives to the expansion in its environmental review; and that it should be able to assess the significance of greenhouse gas emissions. 

The three states submitted evidence in a supplemental filing from GTN’s rate case, which the majority held could not be considered due to late filing. Clements said the supplemental filing should have been accepted because it included information central to the case. 

The states had tried to get analysis from the firm that their laws would cut its demand, but GTN dismissed those concerns as speculative; then in the rate case, it claimed future demand was at serious risk because of their climate laws, Clements wrote. 

“Although GTN asserted in its data request response that the effect of state laws was too speculative to be considered for purposes of the certificate proceeding, its witnesses said the opposite for purposes of supporting an increase in GTN’s rates,” Clements said. 

Contracts for 40% of the pipeline’s existing capacity will expire in 2028, and local delivery companies subject to the three states’ laws hold 41% of that expiring capacity. 

“Thus, it is entirely possible (if not likely) that the three shippers who signed precedent agreements could access this existing capacity to meet their transportation needs as the current capacity holders reduce their reliance on natural gas pursuant to state legal mandates,” Clements said. 

FERC should have accepted the state’s filing of the rate case information because it undermines the foundation of the certificate order to the point where it cannot be rationally sustained on rehearing, Clements said. 

The expansion would increase the pipeline’s capacity by 5% and the region’s total pipeline capacity by 1.5%, and the three West Coast states represent 95% of the demand, with Idaho representing just 5%, she said. 

“Intermountain is unlikely to need any new capacity because, as GTN’s own rate case witnesses predict, the stringent decarbonization laws and renewable energy initiatives in Idaho’s neighboring states will drive down regional demand for gas and thereby demand for GTN’s existing gas transportation capacity,” Clements said. 

FERC considered updating its procedures for granting new pipelines certificates, but its proposal ran into steep opposition from the industry and on Capitol Hill, where it helped sink former Chair Richard Glick’s renomination. Clements argued in her dissent that this case shows why an updated policy statement on gas certificates is needed. 

“To avoid repeating these mistakes, the commission should finalize an updated certificate policy statement and implement enhanced procedures allowing us to fully evaluate all factors that actually do bear on the public interest in 2024, including the effect of state laws and renewable energy initiatives,” Clements said. 

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DOE Urges Utilities to Embrace ‘Holistic’ Reliability Solutions

With electricity demand expected to undergo rapid acceleration by 2028 while generation moves from fossil fuels to renewable resources, stakeholders must “pursue the full range of technology, planning and operation solutions” to meet resource adequacy needs, the U.S. Department of Energy said in a report released this week. 

DOE said “The Future of Resource Adequacy,” published April 17, was meant to highlight the challenges of maintaining resource adequacy in the face of the changing grid and spread awareness about potential solutions, as well as the “unprecedented funding” for grid infrastructure available through the Infrastructure Investment and Jobs Act and the Inflation Reduction Act. 

The report identified several growing threats to resource adequacy, which NERC defines as “the ability of the electric system to supply the aggregate electrical demand and energy requirements of the end-use customers at all times.” Growth in demand is chief among these, but the rising incidence of extreme weather events because of climate change is another factor; DOE noted that the U.S. experienced 28 weather and climate disasters in 2023 that each caused more than $1 billion in damages. 

There are no simple answers to these problems, DOE said, pointing out that the complexity of the grid makes electric reliability “intrinsically a systemwide property that cannot be ensured by any individual resource or technology.” The report recommends “holistic” thinking on reliability. 

Resource adequacy goals, for example, can be met using a variety of resource types to ensure that a shortage of one resource — such as sunlight or natural gas — does not imperil the entire system. Drawing on data from the National Renewable Energy Laboratory, DOE noted that synchronous generation facilities present a wide range of responses to extreme temperatures, with combustion turbine plants showing the highest rate of outages at temperatures of -15 degrees Celsius but steam turbines leading in outages at 35 C. 

Historical outage rates for fossil and nuclear power plans as a function of temperature | DOE

The report noted that new natural gas plants are often grid planners’ “first response … to meet resource needs” because of their “general flexibility, low cost and high-capacity credit, as well as familiarity with the technology.” But the temperature data suggest this approach could cause problems with reliability during extreme weather. 

Instead, DOE presented the example of Xcel Energy, which will replace an 1,879-MW coal facility in phases through 2030. Rather than replacing the plant with a natural gas combined cycle plant as originally proposed, the utility decided to build two smaller combustion turbines, 710 MW of new solar capacity, a long-duration storage facility and “transmission lines to facilitate interconnection of up to 1.2 GW of new wind resources.” The utility said this plan would reduce customer costs and its carbon footprint, “all while preserving reliability.” 

DOE also noted the accelerating deployment of energy storage systems, particularly paired with renewable generation to allow the energy from their most productive periods to be shifted to other times of day. Citing data from the Energy Information Administration, the report noted that battery capacity on the grid is expected to more than double by next year. 

Hybrid storage systems at existing generators, or attached to existing proposed projects, have the additional strength that they “generally [do] not have to re-enter the interconnection queue … cutting down on one of the biggest hurdles to greenfield deployment,” DOE noted. 

“The unprecedented availability of tax credits and other funding opportunities through the [IIJA] and IRA creates a compelling environment for exploring all of these opportunities,” DOE said. “Utilities have both the opportunity and the means to plan and deploy a variety of clean technologies to maintain and improve resource adequacy along the path toward the sustainable electric grid of the future.” 

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Calif. Senate Committee Passes Energy-related Bills

A California Senate committee passed a raft of energy-related bills April 16, including legislation focused on grid-enhancing technologies, hydrogen and data centers.  

The Senate Energy, Utilities and Communications Committee voted 18-0 on Sen. Steve Padilla’s Senate Bill 1006, which would require transmission-owning utilities to prepare a grid-enhancing technologies strategic plan to file with the California Public Utilities Commission (CPUC).  

Under SB1006,  the strategic plans would include an implementation timeline, and utilities would report their progress in their integrated resource plans. Starting in January 2026 and every four years thereafter, transmission utilities would be required to work with CAISO to evaluate which of their transmission and distribution lines could be cost-effectively fitted with advanced conductors.   

Padilla (D) pointed to CAISO estimates that the state will need more than 7,000 MW of new transmission capacity each year for the next decade to meet its energy demand and GHG reduction goals.  

Grid-enhancing technologies, such as dynamic line rating systems and advanced power flow control systems, typically are inexpensive hardware or software that can be deployed quickly, the bill states. Along with advanced conductors, the technologies could increase reliability while reducing transmission line congestion, renewable generation curtailment and wildfire risk.  

The U.S. lags behind other countries in use of the technologies, bill supporters said.   

Julia Selker, executive director of the Working for Advanced Transmission Technologies (WATT) Coalition, called the bill “a huge opportunity” for the state’s economy and decarbonization goals. “Grid constraints are blocking economic development in California, blocking renewable energy, and [this] will help us integrate new large loads,” Selker said, speaking in support of the bill.  

No one spoke in opposition to SB1006, now headed to the Senate Rules Committee.  

Hydrogen Bills

The committee also passed two bills by Sen. Josh Becker (D) that are aimed at accelerating the state’s progress on green hydrogen. The bills also seek to encourage the electrification of industrial processes that rely on fossil fuels. 

SB993 would direct the CPUC to set rates “as low as feasible” to encourage green hydrogen or industrial facilities to use electricity when clean energy is abundant and curtail their demand at other times.   

Customers would only be eligible for the tariff if they are new electrical customers or plan to increase their electrical load substantially after enrolling.   

“What both green hydrogen and electrified industrial heat have in common is that they’re economically competitive only if they have access to inexpensive electricity, and they’re only good climate solutions if they rely on clean electricity,” Becker told the committee.  

Proponents said the bill would support the Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES), a private-public partnership in California. In October, the U.S. Department of Energy announced ARCHES will receive up to $1.2 billion in hydrogen hub funding. (See DOE Designates Seven Regional Hydrogen Hubs.)  

SB993’s opponents include Pacific Gas & Electric. A PG&E representative said the utility is worried about cost shifts that might occur under the bill.   

A second hydrogen bill passed by the committee, SB1018, would exempt certain solar or wind projects from being considered “electrical corporations” subject to CPUC regulation. The exemption would apply if the electricity were provided over private lines exclusively for electrolytic hydrogen production or electrifying industrial heat processes.   

SB 1018 would expand the state’s current “over the fence” exemption for electricity generated for consumption on-site or for one or two neighboring parcels.   

“That works fine for rooftop solar on a home,” Becker said. “But it’s not sufficient for the megawatts of solar, spread across many acres of land, that we’re going to need for a modest hydrogen facility or a factory.”   

The exemption would apply only to solar or wind generation serving new electrical loads.  

Opponents of the bill, including a San Diego Gas & Electric representative, expressed concerns about an exemption “undermining grid planning, safety and reliability.”   

Both hydrogen bills now head to the Senate Appropriations Committee.  

Data Centers

The committee also passed SB1298, by Sen. Dave Cortese (D), which applies to data centers’ emergency backup generating facilities.   

The California Energy Commission (CEC) has licensing authority for thermal power plants of 50 MW or larger but offers an exemption for power plants of 100 MW or less.   

SB1298 would raise the exemption’s cutoff to 150 MW. The bill originally set the cutoff at 200 MW, but Cortese agreed to lower that to 150 MW based on committee feedback. The exemption would be available to data centers’ backup power facilities that are not connected to the grid.   

Before granting the exemption, the CEC must find the proposed facility would not have a substantial adverse effect on the environment or energy resources. If an exemption is granted, the project developer still must obtain local, state and federal permits.  

Cortese noted the surging demand for digital services and said the data center vacancy rate in Silicon Valley is only 1.6%.   

Data centers support businesses of all sizes, he said, including 911 call centers, GPS navigation systems, hospitals and the tech industry.   

“This bill will create larger data center facilities that better meet the demands of California industries,” Cortese said.  

The Bay Area Air Quality Management District opposed the bill based on concerns about pollution from diesel generators that data centers use for backup power. 

The California Air Pollution Control Officers Association said lawmakers should re-examine the exemption’s 100-MW cap to see if it needs to be lowered to protect public health.   

Proponents noted the limited amount of time the backup generators are used.   

Following the committee’s 14-0 vote, SB1298 goes to the Senate Appropriations Committee.  

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ISO-NE Decreases Its 10-year Peak Load Forecast

ISO-NE is decreasing its peak load projections slightly for the next 10 years due to slower-than-expected electric vehicle adoption, managed charging programs and changes to its modeling of partial building electrification.   

The RTO projects a 2033 net winter peak of 26,768 MW and a net summer peak of 27,052, it told stakeholders at the NEPOOL Reliability Committee (RC) on April 17. ISO-NE reduced its 2032 projections by 1.8% for the net summer peak and 2.5% for the net winter peak.  

The net peak projections include demand reductions associated with energy efficiency and distributed behind-the-meter (BTM) resources. The results will be included in ISO-NE’s 2024 Capacity, Energy, Loads and Transmission report. 

Both net peak demand and overall net energy have declined significantly in New England over the past two decades due to efficiency efforts and the proliferation of BTM solar. But as the New England states aim to electrify large parts of their transportation and heating sectors, ISO-NE projects load growth to accelerate in the latter part of this decade.  

While the New England grid currently reaches its annual peak loads in the summer, ISO-NE anticipates electrification eventually will cause the region’s winter peaks to surpass summer peaks. 

“Beyond the forecast horizon, by the mid-2030s, electrification is expected to cause winter peak demand to become the typical, prevailing peak season,” said Victoria Rojo of ISO-NE. 

The increase in the winter peak could be partly mitigated by the warming climate, which is causing milder winter weather in New England — 2023 was the warmest winter on record for the Northeast according to data from the National Oceanic and Atmospheric Administration. 

ISO-NE’s load projections are based on weather data from the past 30 years and do not consider climate forecasts. Rojo said the RTO hopes to update its methodology to include climate projections in the 2025, 10-year load forecast.  

Distributed Energy Resource Data Collection

ISO-NE also proposed a new process to “formalize and standardize the data collection of size, location and characteristics of distributed energy resources.” 

The proposal would make distribution providers responsible for providing ISO-NE with data about individual DER installations, including size, fuel type, in-service date and location. The RTO currently collects DER data through voluntary disclosures from distribution providers. 

Improved DER data collection would bring a range of benefits for the region, ISO-NE said.  

“More accurate forecasts and historical accounting lead to more efficient market outcomes and less uncertainty in system operations and planning,” said Dan Schwarting of ISO-NE. 

Schwarting added that improved DER data would lead to “more accurate interconnection studies and more efficient/faster study timelines for FERC– and state-jurisdictional generation projects to interconnect to the transmission system.” 

ISO-NE also intends to develop a database collecting DER data so it can better access and use the data, Schwarting said. The RTO plans to present the RC with a draft procedure in May and aims for a vote in June. 

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Xcel Acknowledges Prairie Island Outage Result of Drilling Accident

Xcel Energy has revealed that a lengthy outage at its Prairie Island nuclear plant was caused by workers inadvertently drilling through a bundle of cables last fall.  

The company admitted to inadequate supervision of an excavation and a failure to use ground radar to sweep the area at the nearly 1.2-GW Minnesota nuclear plant in an event report to the Nuclear Regulatory Commission last month.  

Xcel chalked up the severed cables to a “human performance issue” that combined “weakness in the excavation permit approval process as well as … inadequate oversight of the non-nuclear supplemental workers.”  

“Site personnel reviewing and approving the permit were not adequately intrusive to ensure that all interferences had been properly identified prior to approving the permit,” Xcel wrote, adding that its use of ground-penetrating radar prior to the drilling was patchy and wasn’t conducted over the DC cable’s location.  

Xcel also blamed “procedural weaknesses and poor communication” between its departments regarding its supervision of the drilling crew.  

The company eventually returned Prairie Island to service in mid-March, two months later than it initially estimated it would have the plant heated up.  

According to the Star Tribune, Xcel wasn’t immediately forthcoming about the cause of the outage, originally framing it as an “equipment issue” between the grid and its turbine.  

Xcel said the mishap occurred Oct. 19, 2023, when Prairie Island’s Unit 1 was operating at full capacity. Non-nuclear work crews were onsite, performing sideways, underground drilling for a project to replace one of the AC power cables between the substation and the plant when they accidentally drilled through a DC cable bundle containing control cables.  

At the time, the plant’s second unit already was offline, having been powered down two weeks earlier for refueling and scheduled maintenance.  

The boring into the cable caused multiple substation breakers in the switchyard to automatically open, Unit 1’s turbine to trip and led to a reactor trip with “a loss of all non-safety related buses,” Xcel said. The company said operators responded as intended and safely brought the plant into a hot standby mode.  

Xcel reported that when Unit 1 tripped, a pump to maintain spent fuel cooling went offline, but another pump was able to compensate without a rise in temperature.  

Xcel said it was forced to replace the damaged control cables before Unit 2 could start up again and since has made “multiple procedure changes … to address the identified gaps and prevent recurrence of this event.” It also said no radiological impacts occurred because of the trip and neither its personnel nor the public’s health and safety were affected.  

In an emailed statement to RTO Insider, Xcel spokesperson Kevin Coss said Unit 1 “safely” took itself offline as the plant is designed to do.  

Minn. Department of Commerce to Weigh in

Xcel is seeking to recoup from ratepayers the fuel and power purchase costs it was forced to make absent the plant’s operation. 

The Minnesota Department of Commerce has opened an investigation into Xcel’s 2023 nuclear outages. In an April 15 filing in response to Xcel’s 2023 fuel clause adjustment charges, the agency said it is wrapping up its probe and will provide written comments and recommendations as to Xcel’s 2023 nuclear fuel clause adjustment charges within a month. The department otherwise recommended the Minnesota Public Utilities Commission approve the non-nuclear aspects of Xcel’s fuel cost petition (E002/AA-22-179).  

The Department of Commerce has questioned why Xcel’s unforced nuclear outages were 995.9 GWh higher than forecast in 2023. Xcel attributed the spike to the cable damage that affected both Prairie Island units. However, the company has said the damaged cable bundle itself was aging and risked water damage, which eventually would have led to a Prairie Island shutdown anyway. 

“This will now avoid the need for a shutdown of both units at a later date. We also used the fact that both units were offline to invest in long-term upgrades and to conduct additional maintenance activities, all of which sets the stage for the plant to operate reliably into the future,” Coss said.  

Prairie Island’s continued operation factors into Xcel’s plan to comply with Minnesota’s law to achieve 100% carbon-free energy by 2040. The utility has said it will require 20-year extensions on the two units’ operating licenses to keep them operating through the early 2050s. Xcel this year asked for a certificate from the Minnesota Public Utilities Commission to store more spent fuel at Prairie Island in above-ground casks.  

The Minnesota Department of Commerce is soliciting public comment on the storage expansion at Prairie Island and has scheduled two public meetings this month.  

Coss noted that Prairie Island supplies more than 1 million customers in the Upper Midwest with carbon-free energy and is poised to play an important role in achieving Minnesota’s mandate.  

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DOE Issues Transmission Interconnection Roadmap

The U.S. Department of Energy has released its roadmap to speed interconnection of new clean energy projects to the nation’s grid. 

The framework announced April 17 is also intended to clear the queue of backlogs that have developed in the past decade, during which renewable energy interconnection requests have grown by 300 to 500%. 

It is intended as a guide for stakeholders, including transmission providers, interconnection customers, regulators, manufacturers, consumer advocates and energy justice communities. It is a collection of potential strategies rather than a rigid list of prescriptive fixes.  

DOE said its Interconnection Innovation e-Xchange (i2X) began working on the first-of-its-kind “Transmission Interconnection Roadmap” in June 2022. Midway through the process, in July 2023, FERC issued its landmark Order 2023, seeking to accomplish many of the same interconnection streamlining goals. 

The DOE roadmap’s authors indicate the new document contains some solutions that relate to Order 2023 while other solutions support a longer-term evolution of the interconnection process.  

The roadmap is intended to complement and support implementation of Order 2023 by focusing on issues that Order 2023 may not resolve, such as balancing stricter requirements placed on interconnection customers with open access and equity considerations; incentivizing faster interconnection studies; and better coordinating affected system studies. 

The roadmap also seeks to address issues not raised in Order 2023, such as data transparency, automation, cost allocation and workforce development. 

The roadmap’s authors anticipate further overlap as FERC completes its rulemaking on transmission planning. The interconnection process and transmission planning are so closely linked that some of the roadmap’s solutions involve transmission planning, the authors write, but its focus is on interconnection reform. 

DOE later this year expects to issue a draft of a companion roadmap focusing on the distribution grid. 

“Clearing the backlog of nearly 12,000 solar, wind and storage projects waiting to connect to the grid is essential to deploying clean electricity to more Americans,” U.S. Secretary of Energy Jennifer M. Granholm said in a news release.  

Goals and Suggestions

The roadmap frames the problem as one of volume: The U.S. grid saw fewer than 1,000 interconnection requests per year in the 2000s and as many as 3,000 per year in the past decade. The generation capacity represented in these requests has jumped from 150-200 GW per year to 400-750 GW. 

The roadmap is framed around four primary goals, and it suggests solutions for each: 

    • Increase data access, transparency and security for interconnection by improving data on projects already in queues; enhancing interconnection study models and modeling assumptions; and developing tools to manage and analyze data. 
    • Improve the interconnection process and timeline through better queue management; improved affected system studies; a more inclusive and fair process; and workforce development focused on technical expertise needed in many industry professions. 
    • Promote economic efficiency in interconnection through better cost allocation; closer coordination between interconnection and transmission planning; and a revised model for interconnection studies. 
    • Maintain a reliable, resilient and secure grid by improving interconnection reliability assessment models and tools, and by developing comprehensive interconnection standards for things such as IBR capabilities and expected project performance. 

The roadmap also includes four target metrics by which to judge improvements: 

    • An average time of less than 12 months for completed projects to move from interconnection request to interconnection agreement. As of 2022, this is averaging 33 months; the best performance since 2003 was 18 months in 2005-2008. 
    • A standard deviation of interconnection costs of less than $150/kW for all projects. As of 2020-2021, it was $551/kW; the best since 2007 was $154/kW in 2010-2011. 
    • A completion rate of greater than 70% for projects that enter the facility study phase. As of 2016, it was 45%; the best since 2006 was 55% in 2007. 
    • Zero annual NERC disturbance events involving unexpected tripping of IBRs not identified in offline analysis due to inaccurate IBR models. In 2022 there were four such events; the last time there were zero was in 2019. 
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DOE Report Highlights Benefits of Advanced Grid Technologies

Advanced grid technologies can help expand the grid quickly and relatively cheaply, according to a new report from the U.S. Department of Energy. 

The Pathways to Commercial Liftoff: Innovative Grid Deployment report, released April 16, focuses on identifying ways to accelerate deployment of commercially available, but underused, advanced technologies over the next five years on existing transmission and distribution infrastructure. The technologies can quickly respond to accelerating grid pressures such as the need to expand capacity in the face of rising demand, enhancing reliability and supporting integration of clean energy. 

“The majority of the nation’s transmission and distribution lines are drastically overdue for an upgrade, which is why President Biden’s Investing in America agenda is so critical to bring the grid up to date,” Energy Secretary Jennifer Granholm said in a statement. “DOE’s new Innovative Grid Deployment Liftoff report outlines the existing tools that can be deployed in less than five years to modernize the nation’s power sector, making it more secure and reliable to deliver cheaper, cleaner power to American consumers.”   

The technologies covered include advanced conductors, high-voltage direct current lines, advanced distribution management systems, dynamic line ratings (DLRs), topology optimization, storage as transmission and distribution, data management systems and others. Deploying the advanced grid solutions could cost-effectively increase the capacity of the grid by 20 to 100 GW of incremental peak demand when installed individually, the report said. 

Making sure the grid has enough capacity is important to many of the projects DOE has funded recently, Jigar Shah, director of the agency’s Loan Program Office, told reporters. 

“Our other manufacturing and energy generation applicants and grantees need to be able to connect to the grid,” Shah said. “If our applicants can’t connect to the grid quickly, that’s going to meaningfully impact our ability to underwrite their debt.” 

The report was developed by staffers from around DOE with deep engagement from the private sector, said Vanessa Chan, director of the Office of Technology Transitions. 

“The liftoff report breaks down the value chain of various portions of the economy and sketches a road map for the private sector to deploy the solutions that we need,” Chan said. “So, in basic terms, [the report covers] things like: What cost do we have to hit in order for these technologies to take off? What are the technological and market-driven barriers that we have to overcome? What’s the amount of investment that we need where and by when?” 

While the grid needs to be expanded with new transmission and distribution investment, major new lines can take a long time to build and the GETs identified in the report can be deployed much more quickly, said Grid Deployment Office Director Maria Robinson. 

“We’re talking about three to five years deployment of key commercially available — but what we believe to be underutilized — advanced grid technologies and applications, and specifically how we can leverage existing transmission and distribution systems,” Robinson told reporters. 

Most of the solutions cost less than a quarter of traditional alternatives and can be deployed quickly, since they use existing infrastructure. 

DOE thinks the technologies can become a self-sustaining industry within three to five years, with “liftoff” happening when utilities and regulators comprehensively value and integrate advanced solutions as part of grid planning and operations. Pursuing between six and 12 operational deployments across a diverse set of utilities can cut risks enough to scale up the GETs industry, DOE said. 

Besides building evidence for how the technologies work and getting utilities and grid operators comfortable with using new technologies, the industry’s economic models and incentives must be updated for GETs to take off. 

“For regulated utilities, this will require regulators to lead in aligning utility compensation models with the value generated from, and costs of, advanced grid solutions to deliver ratepayer benefits — e.g., implementing performance-based regulation, allowing some operational expenditures to be capitalized,” the report said. “New mechanisms are needed that allocate costs in ways that better align with beneficiaries and equitably share benefits.” 

Grid operators also need to know how to include GETs in system planning and prioritize them for investments, the report said. That requires a comprehensive understanding and method for evaluating the costs and benefits of the technologies. 

The grid will benefit if the industry institutes the right reforms to use advanced transmission and distribution technologies to their full potential, it said. 

“Using just one-fifth of the current investment in conventional transmission and distribution asset replacement to instead upgrade assets with advanced grid solutions could nearly double industry investment in advanced grid solutions, driving greater grid impacts without increasing costs to ratepayers,” the report said. 

Maintaining reliability and keeping the grid’s frequency at 60 Hz are vitally important, and one way of showing utilities and grid operators the technologies can do those things while enhancing capacity is through demonstrations, including one DOE has funded at Philadelphia-area utility PECO, Robinson said. 

“A lot of this is just increasing awareness and making sure that the regulators also feel comfortable with taking these approaches as well,” she added. 

AES and LineVision Case Study on Dynamic Line Ratings

Segments of the industry have been working on rolling out the technologies, with LineVision and AES releasing a case study April 15 on the use of DLRs on five high-voltage lines across AES’ utility territories in Ohio and Indiana. DLRs can increase reliability by giving operators a better sense of how their lines are operating, LineVision CEO Hudson Gilmer said in an interview. 

“It’s providing utilities better data with which to do their jobs,” Gilmer said. “In the absence of monitoring of these lines that are really the backbone of the grid, utilities are guessing; they’re making conservative static assumptions about how much power they can put through the lines. And what this technology does is for the first time, it really allows them to see actual conditions and know precisely how much power they can put through those lines.” 

While the case study found that, on average, DLRs can increase a line’s capacity by 9 to 27% in the summer and up to 81% in the winter, Gilmer said they could sometimes help grid operators recognize when their assumptions are too generous and prompt them to dial back a line’s capacity, such as on a hot summer day with no wind. 

The case study involved installing LineVision’s monitoring technology on major backbone lines, but results indicated it could benefit lower-voltage transmission as well, although the biggest savings were on the 345-KV lines. 

The project involved installing 42 sensors in just eight weeks, with individual installation times of just a half-hour without considering travel time to the location. The quick installation time means they can easily be moved around as the grid changes, but Gilmer believes they might become standard across the entire system in the long term. 

“There’s one approach, which is deploying it almost like Band-Aids on that small number of problem lines,” Gilmer said. “But another philosophy is to say, ‘Why wouldn’t I want this data on my entire transmission system?’ So, these are the high-voltage lines that form the backbone of the grid. Wouldn’t your operators want to know exactly how much power they can put through, and if there are any anomalies that they need to be concerned about?” 

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Stakeholders Spar over PJM Request to Recalculate Capacity Auction Results

Stakeholders filed comments April 11 debating PJM’s request that FERC direct it to recalculate the results of the 2024/25 Base Residual Auction and rerun the third Incremental Auction (IA) based on those results, with general support from generators and opposition from state regulators and consumer advocates (ER23-729). 

The 3rd U.S. Circuit Court of Appeals in March vacated FERC’s order allowing PJM to revise the locational deliverability area reliability requirement for the DPL South zone after the BRA had been conducted but before the publication of its results, finding that it constituted a violation of the filed-rate doctrine. 

PJM on March 29 petitioned FERC to order it to use the results that would have been the outcome in December 2022 had it not revised the reliability requirement. It also requested to rerun the capacity period’s third IA, completed March 11, arguing that matching the “new” BRA results with those of the IA would be too complicated. (See PJM Awaiting FERC Response to Court Rejection of 2024/25 Capacity Auction Parameters.) 

The issue stems from PJM identifying a substantial increase in capacity prices because of the interaction between a “misalignment” in resources that offered into the auction and the expected resource pool based on the reliability requirement. The RTO asked FERC to allow it to revise the calculation of the requirement after bids had been received to exclude generators expected to offer that ultimately did not. (See Capacity Auction ‘Mismatch’ Roils PJM Stakeholders.) 

PJM requested FERC to act by May 6. It argued that rerunning the third IA would prevent generators that did not clear under the original auction from being assigned a capacity commitment with less than a month to make any preparations necessary to meet their obligations before the start of the delivery year (June 1). Some generators that did not originally clear may also have sold their uncommitted capacity through bilateral transactions, raising the risk that capacity may be double-counted if those resources are picked up should the BRA be rerun with different parameters. 

Should the commission decline to rerun the auction or not reach an order by then, PJM presented a “less optimal” alternative of allowing it to relieve market sellers of capacity commitments that both increased through rerunning the BRA and exceed what they reasonably believe they could provide. Market sellers would have seven days to request that PJM relieve them of their capacity obligations, which the RTO expects to be such a small amount that finding replacement capacity would not be necessary. PJM said that option would remain viable until May 22. 

“In other words, only a capacity resource that is committed in the recalculated Base Residual Auction to provide more megawatts than it is now capable of providing (due to either bilateral transactions or commitments from the February 2024 third Incremental Auction of capacity not committed under the prior Base Residual Auction results) would be eligible to be relieved of such excess megawatts,” PJM explained. 

Consumer Interests Urge Rejection

In a joint protest, several state commissions, consumer advocates and industrial groups urged the commission to reject PJM’s petition, arguing that rerunning the BRA with the original reliability requirement would increase DPL South consumers’ capacity bill by $178 million with little reliability benefit.  

They cited informational auction results PJM posted April 4, which showed what the December auction results would have been if the requirement had not been modified. Those figures, which PJM’s petition proposed using as the new auction results, show an increase in the DPL South clearing price from $90.64/MW-day to $426.17/MW-day, for a regional capacity cost of $288.4 million. 

Rerunning the IA would exacerbate the issues that have made commission reluctant to order auctions be reconducted by substantially increasing load-serving entities’ and consumers’ capacity costs with little time to find ways to lower them, argued the organizations, which included American Municipal Power, the Delaware Division of the Public Advocate, Delaware Energy Users Group, Delaware Municipal Electric Corp., Delaware Public Service Commission, Maryland Office of People’s Counsel and Old Dominion Electric Cooperative. 

“Rather than proposing to maintain the posted BRA results in light of these problems, PJM doubles down and proposes to rerun the third Incremental Auction. But that will not solve problems; it will instead create even greater disruption,” they told FERC. “PJM … ignores that doing so could adversely impact market participants who have relied in one way or another on the already completed third Incremental Auction.” 

Instead, they argued FERC should reaffirm that the BRA results PJM posted in February will stand because the commission’s obligation to protect consumers outweighs the general presumption that resolving a legal error should revert parties to their standing prior to the error. 

“The equities especially disfavor rerunning the auctions in this case, where PJM and one commissioner have acknowledged — and no one has meaningfully disputed — that the new prices reflect an unjust and unreasonable result of using an inflated reliability requirement, at odds with actual reliability needs, that increases capacity charges by more than $177 million, or 160%, with no consumer benefit,” the organizations said, referencing Commissioner Mark Christie’s concurrence with the commission’s order accepting PJM’s changes to the auction parameters.  

“Indeed, the commission here already balanced the equities when it weighed customers’ interest in paying only a just-and-reasonable rate against the generators’ allegedly settled expectation of exorbitant rates driven by use of an inflated reliability requirement, and concluded that the former outweighed the latter.” 

“PJM’s proposal would have profound adverse impacts on consumers in the Delmarva peninsula. Granting PJM’s proposal would serve only to provide power plant owners an unjustified windfall through massive price increases. It should be rejected,” Maryland People’s Counsel David Lapp said in a statement. 

In a statement regarding the Maryland Public Service Commission’s own protest, Chair Frederick Hoover said PJM’s proposal would result in “excessive capacity costs” for consumers and replace auction parameters the commission found just and reasonable last year with a flawed market design. 

“Allowing PJM to apply the same flawed market design that it has once correctly characterized as being unjust and unreasonable would be unconscionable,” Hoover said. “With FERC’s acknowledgement of the consequences of a flawed market, PJM already set the fair price for electric capacity well over a year ago. We are asking FERC to require PJM to retain those rates in order to ensure that customers on the Delmarva Peninsula will not be harmed by having to pay for reliability at inflated prices with no economic or reliability justification.” 

Generators Supportive of New BRA Results, Divided on IA

The Electric Power Supply Association and PJM Power Providers, which appealed FERC’s order to the 3rd Circuit, jointly supported PJM’s petition, saying that resolving the case before the delivery year begins is imperative. 

While they said both routes PJM proposed were acceptable, they preferred leaving the third IA results in place and instead allowing market sellers to ask the RTO to relieve any increased capacity obligations they could not serve. Rerunning the IA could result in unintended consequences by allowing all market participants to adjust their positions after the results of the original IA had been posted, which they said is unnecessary because a smaller number of participants are expected to be affected by the issues PJM is seeking to resolve. 

Constellation Energy supported PJM’s entire proposal, stating that the IA was based on the same parameters the court found invalid and that rerunning it would allow market sellers to adjust their offers to account for changes in the BRA parameters. 

“If the BRA results are recalculated but the third Incremental Auction is not rerun, there will be a disconnect between the quantity of capacity procured in the BRA and the quantity needed in the third Incremental Auction” Constellation said. “Additionally, market participants should have a meaningful opportunity to adjust their participation in the third Incremental Auction in light of the recalculated BRA outcome.”