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August 16, 2024

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DOE Awards $26M to Clean Energy Technology Projects

The U.S. Department of Energy on Wednesday announced it is funding eight projects across 13 states and Puerto Rico to demonstrate how solar, wind, storage and other clean energy resources can support grid reliability and efficiency.

DOE will allocate $26 million in Infrastructure Investment and Jobs Act funding through its Solar and Wind Grid Services and Reliability Demonstration Funding Program, which is designed to demonstrate the reliable operation of energy systems that have up to 100% of their power contribution from solar, wind and battery storage resources.

The projects being awarded deploy “innovative” clean energy technologies at 15 sites “to build and support a resilient grid that automatically adjusts to changing demands,” according to the department. They will support the administration’s “efforts to accelerate a decarbonized grid, expand the adoption of affordable clean energy and strengthen America’s energy security while combating the climate crisis,” it said.

Research teams comprising utilities, laboratories, universities and industry will test how wind and solar plants can more reliably transmit electricity and protect against disruptions to high-voltage power lines. The projects will also monitor and test controls that allow the grid to restore power quickly and efficiently after blackouts.

“As threats and climate risks to America’s energy infrastructure continue to evolve, DOE is laser-focused on ensuring our power grid is strong and reliable as it incorporates a historic level of renewable resources,” Energy Secretary Jennifer Granholm said in a statement. “Today’s announcement will help build a resilient grid that the American people can trust to deliver reliable, affordable, clean electricity to their homes and businesses.”

A recent study by DOE’s National Renewable Energy Laboratory’ found that wind and solar energy could provide as much as 80% of generation on a grid run by 100% clean electricity. Achieving those levels would require rapid and sustained growth in installed solar and wind generation capacity, it said, with nuclear energy helping to make up the difference.

The study modeled four scenarios that deployed new clean energy technologies at an unprecedented scale and rate to achieve 100% clean electricity by 2035. Wind and solar energy would provide 60 to 80% of generation in the least-cost electricity mix in 2035; overall generation capacity would grow to roughly three times the 2020 level by 2035, including a combined 2 TW of wind and solar.

The selected projects and awards are:

  • Consolidated Edison’s initiative to demonstrate transmission protection strategies in New York and Virginia that reduce outages as the grid moves to inverter-based generation. If successful, the project will demonstrate to the transmission system protection, operation and planning industries that the grid can operate safely and reliably with any mix of energy sources, including 100% inverter-based resource (IBR) generation. ($3 million)
  • an Electric Power Research Institute project with multiple balancing authorities and utilities to demonstrate grid services capabilities in Michigan, Nebraska, Texas, New Mexico and California. ($3.4 million)
  • General Electric Renewable Energy’s project demonstrating grid-forming inverters at the Great Pathfinder wind plant in Iowa. ($3.5 million)
  • a National Renewable Energy Laboratory project in Hawaii that aims to further the understanding of the grid’s behavior in response to faults in scenarios with high IBR levels. ($2 million)
  • Pacific Gas and Electric’s development of an automated analysis tool for utility engineers to address rapid changes in the electric grid, such as increased solar generation. ($2.5 million)
  • Portland General Electric’s demonstration of grid-forming inverters at the Wheatridge Renewable Energy Facility in Oregon, North America’s first energy center to combine wind, solar and energy storage systems in one location. ($4.5 million)
  • the University of Illinois at Chicago’s project in Illinois and Puerto Rico using an innovative modeling, protection and control framework to ensure the bulk power system’s reliable operation with 100% IBR generation, as they have much different fault characteristics than traditional synchronous generators. ($3 million)
  • Veritone’s project designed to boost confidence in renewable power by using the company’s artificial intelligence-powered distributed energy resource management system (iDERMS) technology in New Mexico. ($3.9 million)

DOE and its applicants will go through a negotiation process before any funding is issued. The department could cancel negotiations and rescind the selection for any reason during that time.

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ISO-NE Plans 2025 Launch for Day-Ahead Ancillary Services Initiative

MARLBOROUGH, Mass. — ISO-NE is targeting March 2025 for the launch of its Day-Ahead Ancillary Services Initiative (DASI) and predicting that its increased energy market costs will be offset by capacity market savings.

ISO-NE analyst Ben Ewing and economist Andrew Withers presented the RTO’s analysis of DASI’s impact to the Markets Committee on May 9.

DASI’s revised market design is intended to procure and price the ancillary services needed for a reliable next‐day operating plan with increasing renewable penetration.

DASI will cover any gaps when the day‐ahead market’s physical energy supply awards are below the RTO’s forecast real‐time load. It also will procure day-ahead flexible response services to ensure the system can recover from sudden generation losses and respond quickly to fluctuations in net load. (See ISO-NE Outlines More of Plans for Capacity Accreditation, DA Ancillary Services.)   

“With DASI, these reliability requirements will be satisfied within the clearing of the day-ahead market (DAM),” the RTO said.

Ewing said the RTO had been considering a launch between December 2024 and March 31, 2025, but settled on March 1 because of stakeholders’ desire to gain experience with the design before the winter, which has a higher potential for stressed conditions. If the deadline is met, the final procurement period for the Forward Reserve Market (FRM) will be Oct. 1, 2024 to Feb. 28, 2025.

Stakeholder votes on the proposal are expected in July and August.

Impact Assessment

Withers said DASI is estimated to increase energy and ancillary services (E&AS) costs by $100 million (1.1%) annually, with a commensurate reduction in capacity costs.

The elimination of 10-minute non-spinning reserve (TMNSR) and 30-minute operating reserve (TMOR) credits with the FRM sunset is expected to reduce E&AS costs and revenues.

Eliminating the FRM’s failure to reserve and failure to activate penalties will increase E&AS costs and revenues. The RTO’s analysis did not quantify potential changes to real-time (RT) costs, which are expected to be small relative to the change in FRM payments and would be difficult to estimate.

Energy Cost Rise (ISO-NE) Content.jpgBased on an analysis of 2019-2021 data, ISO-NE expects energy and ancillary services costs to increase by about $100 million (1.1%) annually from the Day-Ahead Ancillary Services Initiative (DASI). The RTO expects the increase to be largely offset by reduced capacity costs. | ISO-NE

For the 2019–2021 study period used by the RTO, eliminating the FRM is expected to reduce E&AS costs by $26.4 million annually.

Under DASI, suppliers of DA energy and ancillary services will receive payments for a new DAM constraint, the forecast energy requirement (FER) and new DAM products: energy imbalance reserve and flexible response services (FRS), including day-ahead 10-minute spinning reserve, day-ahead 10-minute non-spinning reserve and day-ahead 30-minute operating reserve.

The RTO projects will reduce DA net commitment period compensation (NCPC) uplift payments by $9.1 million (74%), to between $2.6 million and $3.7 million annually.

ISO-NE expects to consider changes to NCPC rules from DASI next year. “These rules have not yet been assessed or designed,” the RTO said.

Capacity Costs

Withers said the RTO expects the $100 million E&AS increase to be “roughly” offset by reduced capacity costs in the long run, reflecting the reduced “missing money” that resources need to recover.

“In the short run, however, predicting changes to capacity costs is more difficult,” the RTO said.

The RTO also said that the effects of DASI on E&AS revenues would vary based on resource types, which could impact which resources are impacted by capacity clearing prices, as well as lead to changes in net cost of new entry.

Tariff Changes

The proposed tariff changes borrow from those in the Energy Security Improvements (ESI) proposal in 2020. FERC rejected the ESI proposal in October 2020, saying it would add substantial costs “without meaningfully improving fuel security” (ER20-1567). (See FERC Rejects ESI Proposal from ISO-NE.)

The RTO said the new DASI mitigation rules included in the tariff changes “reflect the most significant tariff redline additions to those introduced with ESI.”

These included updates to day-ahead ancillary services (DA A/S) offer requirements, format and strike price determination, and FRS and FER constraint demand quantity specifications.

Mitigation

Parviz Alivand, senior economist for ISO-NE, presented on mitigation enhancements proposed by the RTO, noting that “closeout and certain avoidable input costs associated with DA A/S are not explicitly addressed by current tariff provisions.” 

The RTO is looking for stakeholder feedback on mitigation-related cost recovery, which it is requesting by May 19. Alivand said the RTO would publish the tariff language for stakeholders before the June meeting of the Markets Committee.

The FERC filing process for recovery of losses would remain unchanged.

Alivand said ISO-NE opposes mandating that participants net real-time market profits against DA A/S losses.

“A participant that expects to make a cost recovery claim related to DA A/S mitigation would have incentive to raise its RT offers to show smaller RT profits,” Alivand said.

The RTO did not rule out netting profits and losses between different DA energy and DA A/S products, saying that this should be reviewed on a case-by-case basis.

“It is possible that DA A/S mitigation increases the DA energy profits, suggesting netting is appropriate, or that DA A/S mitigation decreases, or does not change the DA energy profits, suggesting netting is not appropriate,” Alivand said.

IMM Analysis

Economist Michael Redlinger and supervisor Jacob Grindal of ISO-NE’s Internal Market Monitor presented their analysis of the DASI mitigation design, saying the Monitor supports the conduct and impact framework for mitigation proposed by the RTO.

“The proposed conduct and impact approach is intended to balance the risks of under-mitigation and over-mitigation,” Redlinger said. “The conduct and impact test thresholds appear reasonable, but it will be important to monitor the appropriateness of the thresholds over time and make adjustments if necessary.”

Consultation will be a key aspect in aligning the expected costs of participants and the IMM reference level and the conduct thresholds. To update reference levels for a market participant, the participant would need to provide the Monitor with detailed cost data backing up the change.

Redlinger also stressed the importance of consultation between generators and the IMM over justifications for physical withholding. He said that detailed consultation could help prevent — but not preclude — a participant from being referred for withholding.

Next Steps

The Markets Committee will consider any design changes to the RTO’s proposal at its meeting in June.

The RTO hopes to have a Markets Committee vote on its proposal and any proposed stakeholder amendments in July, with a Participants Committee vote in August.

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DOE Rolls out New Process for Designating Key Transmission Corridors

The U.S. Department of Energy wants to accelerate permitting and financing for transmission projects currently under development by designating their proposed routes as National Interest Electric Transmission Corridors (NIETCs).

DOE was given the authority to identify these corridors in the Infrastructure Investment and Jobs Act, and on Tuesday, Maria Robinson, director of the Grid Deployment Office, announced the department’s plan to implement that authority via a new “applicant-driven” and “route-specific” process.

Releasing a combined notice of intent and request for information on the new process, Robinson said DOE’s top priority, at least to start, will be on identifying NIETCs (pronounced “nit-cees”) for projects that are already being planned, even if they have not been permitted or financed.

“We’re looking to unlock critical federal investments and regulatory and permitting tools to spur urgent transmission investments needed in specific regions to improve reliability and resilience, as well as reduce consumer costs,” she said during a media briefing. “This approach to selecting corridors will focus on specific needs and targeted geographic locations and seeks to identify transmission corridors that help to ensure targeted and effective relief for American communities from life-threatening electric outages.”

Projects located within a NIETC would be able to tap into $2.5 billion in funding for public-private partnerships made available in the IIJA. The Inflation Reduction Act adds another $2 billion to the pot from its transmission financing loan program, Robinson said.

A NIETC designation “can also allow … FERC to grant permits within a [corridor] border in certain circumstances where states cannot or have not issued those permits after more than one year,” she said, referring to the commission’s “backstop” permitting authority established in the IIJA.

FERC issued a Notice of Proposed Rulemaking on its backstop permitting authority in December, with an extended comment period that ends on May 17 (RM22-7). (See FERC Moves to Implement New Backstop Transmission Siting Authority.)

The NOI lays out proposed guidelines for the potential applicants who will drive the process and the “route-specific” projects they will propose for NIETC designation.

Potential applicants will have “progressed beyond the preliminary concept and … begun actively routing the project and engaging in community and landowner outreach, land surveys or initiation of environmental compliance work,” the NOI says. “However, no particular stage of development is required for an applicant to seek potential designation.”

DOE’s definition of “route-specific” is particularly broad. Applicants will have to document how their projects balance “the need to ensure that the potential route is defined with sufficient specificity to allow for meaningful evaluation of the potential energy and environmental impacts of one or more transmission projects along that route, while also sufficient in size and scope to construct, maintain and safely operate one or more transmission projects in accordance with applicable regulatory requirements and reliability standards and accommodate routine route changes that often occur when siting and permitting infrastructure.”

Advocates Optimistic

The long list of the information an applicant would have to provide to get a NIETC designation includes the geographic boundaries and rationale for those boundaries; how the project would address existing or future transmission needs; and the “economic growth and vitality in the corridor or end markets served.”

Information on environmental impacts will need to be detailed enough for DOE to complete an environmental review under the National Environmental Policy Act (NEPA). That covers everything from “potential adverse effects to cultural and historic resources” to “known or potential impacts” to the U.S. aviation and marine transportation systems, and to a project’s proposed use of previously disturbed lands.

The RFI seeks feedback on the NIETC guidelines, the structure of the application and designation process and how the impacts of any proposed route should be evaluated. It asks if the information requests outlined in the NOI might be “overly burdensome on respondents” but also if additional information should be included in applications.

Rob Gramlich, founder and president of industry consultants Grid Strategies, expects DOE will get a significant number of applications when it releases a request for proposals, possibly in the fall.

“It’s exciting to see this process finally, formally introduced,” Gramlich said in an interview with RTO Insider. “Transmission proponents have been recommending this type of process for a number of years. The department has suggested informally over the years that it would be open to applications for designation, but it’s never really had a formal process like it has introduced today.”

Christina Hayes, executive director of Americans for a Clean Energy Grid, agreed. Advocates have been waiting for DOE to develop a NIETC designation process “that really is consistent with how these [transmission] projects are developed,” she said.

The NOI and RFI released Tuesday will be published in the Federal Register in the next four or five days, triggering a 45-day comment period, according to DOE. The department has also scheduled a public webinar on the proposed guidelines for May 17.

The History of NIETCs

The draft National Transmission Needs Study published in February documented huge gaps between existing lines and what will be needed to reach President Joe Biden’s goal of a decarbonized grid by 2035.

A 2022 study from the National Renewable Energy Laboratory estimated that U.S. transmission capacity would have to grow 1.3 to 2.9 times by 2035. A 2021 study from Princeton University said a 60% increase in transmission may be needed by 2030, followed by a threefold increase by 2050.

DOE was first authorized to designate NIETCs by the Energy Policy Act of 2005, according to a department fact sheet. Following a study of grid congestion and constraints, DOE designated two broad NIETCs in 2007. The Mid-Atlantic corridor included counties in Ohio, West Virginia, Pennsylvania, New York, Maryland and Virginia, and all of New Jersey, Delaware and D.C. The Southwest Area corridor covered areas in California and Arizona.

Recalling that effort, Gramlich said it was too broad. “Those were big, brawny corridors that looked like big blobs and Magic Marker lines across the country, which got everybody anywhere near the paths concerned about whether there’s going to be a transmission line in their front yard,” he said.

The applicant-driven approach “is much more surgical … focused on the actual route that’s likely to be used rather than, you know, 100 hypothetical routes that aren’t likely to be used,” Gramlich said.

Hayes was also optimistic that DOE has refocused “its efforts on how to deploy the transmission that’s needed for a transition to cleaner energy [and] electrification and to respond to extreme weather. … They’re focusing on where cost-effective, well planned transmission would be sited and [looking] at the corridors around those projects.”

DOE’s Robinson stressed that while a “NIETC designation can identify a specific corridor where transmission projects are needed, it does not establish a preference for a specific transmission project or cluster of projects that may be located within a designated corridor.”

The National Transmission Needs Study, which DOE aims to finalize this summer, will also be factored into NIETC designations, Robinson said. One of the study’s key findings is that new transmission that connects the country’s major electrical interconnection areas — East, West, Midwest and Texas — will provide the most value, especially during extreme weather events.

Keeping the Train on the Tracks

One of the IIJA’s more critical and controversial provisions gives FERC backstop siting authority, long desired by transmission developers and proponents but opposed by both red and blue states.

To qualify for this “backstop” permitting, a project has to be located in a NIETC. FERC can approve the project if it has been denied by state or local regulators, if they have taken no action for a year, or if they have conditioned approval on requirements that would either make a project financially unfeasible or unable to relieve congestion or other constraints on a line.

The NOPR issued in December would provide a “pre-application” process that a developer could begin before delays or denial of a permit reaches the one-year mark. It would also set up a 90-day period for a state to respond to a request for a backstop approval.

Hayes sees FERC’s backstop authority as an essential piece of the process for promoting transmission development. “We’re really excited to see how they are seeking to work with states by providing that extra 90 days after the one year for states to explain what they’re doing,” she said, while also setting up the pre-application filing process.

“They’re being really thoughtful about how to keep the train on the tracks while being mindful of allowing a process for the states,” she said. “DOE and FERC are thinking about ways to work together to move forward in a way that’s consistent with the statute, consistent with the need for thorough, legally durable environmental reviews, but also making sure that we’re able to deploy the kind of transmission that we need to meet our reliability goals, our electrification goals and our need for cost-effective planning.”

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NERC Publishes Cybersecurity Planning Framework

NERC on Monday laid out a framework for transmission planners (TPs) and planning coordinators (PCs) to include cybersecurity in their planning studies to address a “rapidly evolving threat landscape [of] increasingly sophisticated cyberattacks” against the North American power grid.

The Cyber-Informed Transmission Planning white paper is rooted in the 2021 ERO Risk Priorities Report, in which industry stakeholders rated cybersecurity among the greatest risks facing the electric grid. (See Grid Transformation, Cybersecurity Lead 2021 ERO Risk Report.)

With new generation sources and remote-control technologies making up a larger proportion of the grid, experts have warned of a growing “attack surface” that increases the grid’s vulnerability to malicious cyber actors.

The new white paper aims to fulfill a suggestion in NERC’s 2023 Work Plan Priorities that the ERO Enterprise “develop cyber-informed planning approaches … to study, identify, and reduce the number of critical facilities and attack exposure/impact” by promoting the integration of security considerations with utilities’ transmission planning tasks.

“While the electric industry is improving, many organizations have minimal collaboration and coordination between their engineering and security staff in a truly integrated manner,” NERC said in the white paper. “Neither side needs to become an expert in the other discipline; however, there are likely opportunities where increased collaboration and integrated processes can drive better business decisions, cyber-resilient long-term transmission plans, and enhanced [grid] reliability and security.”

Road Map to Reliability

In the first part of the white paper, NERC outlined a “road map” by which TPs and PCs can integrate cybersecurity professionals into their planning process to ensure that cyber risks are accounted for. This strategy took the form of a Cyber-Informed Transmission Planning Framework (CIPTF), a five-step process in which planners and cyber experts:

  • define scenarios for a coordinated cyberattack, particularly involving multiple elements with common security gaps;
  • determine grid elements that might be affected in each attack scenario;
  • conduct studies to analyze the potential performance of the identified elements under attack;
  • analyze outcomes of the planning studies and determine what mitigations might address the identified reliability issues; and
  • implement those mitigations and any other security controls to neutralize the identified risks.

NERC provided a list of scenarios as a sample of the type of situation that TPs could study, while stressing that “there are likely other scenarios … worth of study” based on each entity’s particular circumstances. The ERO’s examples included an outage of multiple distributed energy resources due to compromise of a common manufacturer and outages of multiple transmission substations due to compromise of devices through remote access capabilities.

In addition to the framework, the white paper’s second chapter discusses how the ERO can contribute to security integration.

First, NERC could further integrate cybersecurity into the definition of “adequate level of reliability” (ALR), a term used in the Federal Power Act to specify what standards the ERO can develop and enforce. While the current ALR definition — which NERC is responsible for developing — does mention “cybersecurity events” and “malicious acts,” the report’s writers urged the ERO to revise this description to explicitly include security as a critical component of reliability. They also suggested the addition of an ALR performance objective to ensure that adverse impacts are managed properly.

Along with updating the ALR definition, the paper proposed revising reliability standard TPL-001-5.1 (transmission system planning performance requirements) to address two “shortfalls.” First, according to the current version of the standard, studies of cyberattack impacts only have to address scenarios involving the loss of two generating stations. The paper observed that attacks on multiple stations, “while less likely,” could pose a serious threat to reliability and should be included in studies.

Second, TPL-001-5.1 currently has no requirement for utilities to mitigate any adverse grid performance issues identified; entities are only required to study these issues. The paper presented this as a significant weakness and suggested that a revised standard “encourage” mitigation steps, though did not discuss how this requirement might be put into practice.

In a statement, Mark Lauby, NERC’s chief engineer, said the CIPTF “sets the stage to plan for a more resilient and secure system, addressing the risk in the long-term planning horizon rather than attempting to bolt on security later in the future.” He added that the integration of cybersecurity enhancements could help “to reduce the number of critical stations on the bulk power system.”

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FERC Orders ISO-NE to Reconsider Market Power Mitigation Rules

FERC last week ordered ISO-NE to reconsider its market power mitigation rules to address an “unanticipated and highly atypical” situation that Dynegy Marketing and Trade said caused it to lose more than $900,000 during the December winter storm.

In partly granting Dynegy’s request for recovery of more than $903,000 in costs, the commission’s May 5 order also instituted a show-cause proceeding under Federal Power Act Section 206 requiring the RTO to revise or defend its current rules (ER23-1261, EL23-62).

Dynegy Marketing and Trade, which was acquired by Vistra (NYSE:VST) in 2018, operates the Bellingham, Blackstone, Lake Road, Milford, Casco Bay/Independence and Masspower natural gas-fired generation stations in New England.

On the morning of Dec. 24, ISO-NE’s Internal Market Monitor determined that the size of Dynegy’s fleet relative to the system supply margin made the company a “pivotal supplier” that could potentially exercise market power.

This “structural” test is one of three screens ISO-NE uses to identify potential market power. The RTO’s “conduct” test determines if the participant offered the resource at a price above its “reference level” — a unit-specific price based on its cost of operations — by a certain threshold. The RTO’s “impact” test determines if the resource changed LMPs by more than 200% or $100/MWh, whichever is lower.

Resources that fail all three tests are subject to mitigation, with the duration of the mitigation determined only by the structural test — meaning that even after a resource’s offers no longer exceed the reference level plus threshold, it remains mitigated until it is no longer a pivotal supplier.

Pivotal Supplier

ISO-NE found that Dynegy was a pivotal supplier during hour ending (HE) 1 through HE19 on Dec. 24, resulting in the RTO mitigating “several” of its resources in the real-time energy market, causing them to under-recover their actual real-time energy market costs as natural gas prices rose in intraday markets.

Dynegy said its under-recovery occurred during intervals in which its supply offers were mitigated to lower reference levels and its resources were uneconomically dispatched higher than they would have been without mitigation (“downward price mitigation”).

The company also had offered segments of its supply curves below reference levels, but the IMM mitigated them to the higher reference levels (“upward price mitigation”), pushing Dynegy’s units out of merit and resulting in lower dispatch levels than the company had expected based on prevailing LMPs. Dynegy also said it under-recovered costs in those hours because it was required to buy back its day‐ahead awards.

The company supported its request with an affidavit from consultant Bill Fowler, a longtime ISO-NE stakeholder, who said he had never before seen the use of upward mitigation, nor heard it discussed in stakeholder processes that developed the current rules.

“If a generator is watching its offers being mitigated [in real time] to higher price levels, with the result being unit output is driven to lower megawatt levels than it desires, the generator no longer has an economic incentive to follow the ISO’s dispatch instructions as required, as it would be more profitable to self-dispatch to the higher megawatt levels,” Fowler said.

The tariff calls for mitigation to continue until a complete hour passes during which the pivotal supplier test is no longer exceeded.

As a result, said Fowler, Dynegy’s “offers became meaningless: They would be mitigated to reference until the [pivotal supplier test] condition was over. Adding to the problem, the mitigation would extend to all offer segments, not just those that were above reference.”

Rules that increase offer prices defeat the purpose of market mitigation and undermine reliability, Fowler said. “It is in precisely these situations — with volatile gas prices in scarcity conditions — that we want generators to take extraordinary steps to find ways to secure additional fuel.”

Dynegy’s request for recovery was supported by the New England Power Generators Association but opposed by the Maine Public Advocate, the Massachusetts Attorney General and the Connecticut Office of Consumer Counsel.

Ruling

The commission granted Dynegy’s request to recover costs related to downward price mitigation and recovery of $62,600 in legal costs but denied its request to recover costs related to upward price mitigation, saying the latter recovery was not permitted by the tariff.

But the commission also said the tariff provision that allows ISO-NE to apply upward mitigation may be unjust and unreasonable and can result in “an illogical outcome.”

Raising a seller’s offer “may potentially lead to suboptimal dispatch, and may increase production costs, because when ISO-NE mitigated Dynegy’s offers to a higher level, the market clearing software dispatched Dynegy resources to lower output levels than would have occurred had Dynegy’s offers not been mitigated upward,” FERC said. “ISO-NE likely dispatched other, more expensive resources to higher output levels to replace the output from the Dynegy resources that were dispatched down.”

FERC gave the RTO 60 days to defend the rule or propose a remedy to its concerns.

It said the RTO should consider whether it is appropriate to mitigate a resource to the lower of its submitted offer prices or its reference level for a given offer segment, rather than automatically mitigating all of a resource’s submitted offer segments to reference levels.

ISO-NE also should consider whether its market power screens should continue testing for conduct and impact beyond the first hour that a portfolio of resources is determined to be pivotal and whether there are other scenarios in which participants would be precluded from recovering costs incurred in situations where their supply offers are mitigated upward, FERC said.

ISO-NE spokesman Matt Kakley said the RTO was reviewing the order and had no immediate comment on how it would respond.

Stakeholders will have 21 days to file comments following the RTO’s filing.

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PG&E Looks to Cut Costs of Undergrounding Lines

Pacific Gas and Electric is seeking ways to save time and money on its $25 billion plan to underground 10,000 miles of power lines in high fire-threat districts, CEO Patti Poppe said during a first-quarter earnings call Thursday.

Digging trenches that are 30 inches deep, six inches less than the utility’s longtime standard of 36 inches, will save $25 million this year as PG&E tries to underground 350 miles of line, Poppe said.

“We determined that 36 inches of cover is not required in most places, and there’s little evidence that incrementally deeper conduits are meaningfully safer or more reliable than slightly shallower conduits,” she said.

“While this may not seem like much, a 6-inch change in depth reduces the labor hours required to install our underground conduits and reduces the amount of spoils [excavated earth and rock] created during our trenching activities by approximately 17%,” she said.

Poppe said PG&E is exploring whether “it’s appropriate to put the conduits 24 inches deep, another 6 inches of potential savings, and we’re analyzing the entire undergrounding delivery process through a value stream mapping exercise to identify further opportunities for efficiency, better customer and co-worker engagement, and even more waste elimination.”

The undergrounding effort is part of PG&E’s wildfire mitigation plan (WMP) that it filed with the California Office of Energy Infrastructure Safety (OEIS) in March.

The utility announced its undergrounding plan in July 2021. That year it buried 73 miles of line, and in 2022 it undergrounded 180 miles. From 350 miles in 2023, PG&E plans to ramp up to 450 miles in 2024, 550 miles in 2025 and 750 miles in 2026.

“We will continue to build on this progress during the WMP cycle by undergrounding 2,100 miles of distribution lines in [high fire-threat districts] from 2023 to 2026, effectively eliminating the ignition risk for overhead lines in those areas,” the wildfire plan says. “Between 2023 and 2026, 87% of PG&E’s undergrounding work is planned for the top 20% of risk-ranked circuit segments, as identified by our risk models.”

PG&E intends to file a 10-year undergrounding plan this year with OEIS under the terms of Senate Bill 884, a bill approved last year that provides for expedited review of undergrounding plans submitted by large electrical corporations to OEIS and the California Public Utilities Commission.

Once filed, OEIS will have nine months to review the plan before passing it on to the CPUC, which will also have nine months to review it.

Reduced Miles and Costs

During a February earnings call, Poppe said PG&E had buried line last year for less than the $3.75 million per mile it had originally estimated and expects to bring down the cost of undergrounding to $2.5 million per mile by 2026 through efficiencies of scale and technical advances.

The utility also reduced the scope of its work, saying it would bury 2,300 miles of line by 2026, not the 3,600 miles it originally targeted.

In its 2023 general rate case, PG&E had asked the CPUC to approve nearly $10 billion for three years of undergrounding but revised that figure down to about $6 billion because of the decreased mileage.

Even with the reduced mileage and costs, critics have called the plan expensive and unrealistic.

The Utility Reform Network, a consumer watchdog group, said in a Jan. 23 brief to the CPUC that PG&E had lowered its mileage target because it knew it would not meet its initial undergrounding goals.

“PG&E itself has come to realize that those targets were unrealistic,” TURN said.

Nevertheless, the utility is “moving ahead with plans to underground 350 miles in 2023, at a forecast cost of approximately $1 billion,” TURN said. “PG&E appears committed to this path, even though it has not received any authorization from the commission for any rate recovery for its 2023 undergrounding proposal. Needless to say, PG&E’s undergrounding request is hugely controversial and subject to CPUC disapproval, in full or in part.”

TURN recommended that PG&E should focus its system hardening work on installing covered conductor, “a proven strategy” that would be less than a third of the cost of undergrounding.

PG&E, however, said in its WMP that undergrounding is key to its “stand that catastrophic wildfires shall stop.”

The utility’s overhead lines have been blamed for a series of wildfires starting in 2015 and extending through last year’s Dixie Fire, which burned close to 1 million acres. The fires included the 2018 Camp Fire, which leveled the town of Paradise, killed 84 people and drove PG&E to file for bankruptcy reorganization in January 2019.

PG&E equipment did not cause any large fires in 2022, which the utility partly credited to its use of enhanced fault-detection technology that quickly de-energizes lines when changes in current are detected, limiting ignitions. (See PG&E’s Distribution System Needs Replacing, Monitor Says.)

One result has been a gradual rise in PG&E’s stock price over the past year. Its shares had traded at around $9 to $12/share for more than two years after its emergence from bankruptcy in June 2020 but closed Friday at $17.27/share.

On Thursday, the company reported first-quarter GAAP earnings of $569 million, or 27 cents/share, compared with $475 million, or 22 cents/share, in the first quarter of 2022.

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NEPOOL PC Briefs: May 4, 2023

Historically Warm Last Winter

ISO-NE COO Vamsi Chadalavada on Thursday told the NEPOOL Participants Committee that New England’s overall energy demand was down during the past winter, coming in at approximately 29,300 GWh, compared to the 31,600 GWh average since 2010.

This is the lowest winter energy total reported by ISO-NE going back through 2010, punctuating a clear downward trend over this time period.

Chadalavada highlighted how the expansion of behind-the-meter solar energy, which has significantly outperformed ISO-NE projections in recent years, has helped to ease winter demand.

The low demand was also in part from abnormally high temperatures, which averaged 4.8 degrees Fahrenheit above “normal” — defined as the average temperature over the past 30 years — from December through February. This includes a 35-consecutive-day stretch of above-normal temperatures, nearly extending through the entire month of January.

These warm conditions could increasingly become the new normal in the region, as research has indicated that New England is warming faster than average global temperatures, with the greatest impacts being felt in the winter.

2023/24 Projection 

Looking forward to this coming winter, Chadalavada presented a variety of scenarios modeling the impacts of different severities on the grid. These generally found the region well positioned, with sufficient energy and capacity to meet demand in mild and moderate winter scenarios.

In the case of a harsher winter, with lower-than-normal overall temperatures and several extended cold stretches, the RTO projected that some capacity deficiency actions may need to be taken for a few days, but that emergency measures will likely not be necessary.

He also noted that the Inventoried Energy Program, which compensates generators for storing up to three days of fuel, will remain in place in the winters of 2023 and 2024.

Winter Without the Everett LNG terminal 

Chadalavada also presented the RTO’s modeling of the winter of 2024/25 with and without the LNG import terminal in Everett, Mass., owned by Constellation Energy. The reliability-must-run agreement for the Mystic generating plant, the terminal’s “anchor tenant,” will expire in June 2024. (See Narrow Set of Options for Retaining Everett LNG Terminal.)

The RTO, along with the gas distribution companies, have argued that the terminal is necessary for the reliability of the region’s gas and electric systems, while environmental groups have challenged this conclusion, saying that these needs could be covered by storage investments and demand response programs.

ISO-NE’s modeling, which looked at how the grid would perform under moderate and severe winter scenarios, found “limited exposure to energy shortfalls” without the terminal, compared to essentially no exposure to energy shortages with the terminal. The projected severity of the shortfall depends on the size of the fuel oil inventory and how much additional clean energy — offshore wind in particular — is added prior to the loss of the terminal.

Winter energy and peak load (ISO-NE) Content.jpgWinter energy and peak load in New England from 2010 to 2022 | ISO-NE

 

The RTO concluded that an increased fuel oil inventory could fully cover the energy shortfall in the case of a moderate winter, and mostly mitigate the shortfall in the case of more extreme winter conditions.

Despite these findings, Chadalavada cautioned against jumping to the conclusion that the terminal will no longer be necessary following the expiration of the existing contract, owing to potential impacts the loss would have on the gas system, as well as on the electric system in the winters following 2024/25.

“The ISO doesn’t have the expertise to assess the operational capability of the regional pipeline system without Everett and will rely on the expertise of pipelines and the [local distribution companies] to identify any operational concerns,” Chadalavada said.

The RTO has been collaborating with the Electric Power Research Institute to study the potential long-term effects that the loss of the Everett terminal would have on reliability in the region. The first phase of this study, projecting out to 2027, is set to be released this Friday.

Order 2222 Compliance

The committee endorsed tariff revisions to comply with FERC Order 2222 in response to a commission directive, with a filing expected Tuesday.

The PC voted along the same sector lines as the Markets Committee did when it endorsed the revisions last month, with almost exactly the same amount of support: about 78.6%. (See “Compliance Filing on DER Aggregation,” ISO-NE Stakeholders OK DER Aggregation Plans, Generator Relief.)

FERC in March rejected certain elements of ISO-NE’s original proposal to comply with Order 2222, which directed RTOs and ISOs to allow distributed energy resource aggregations to fully participate in their markets. The commission ordered further revisions by several different deadlines, depending on the element.

The new revisions are those due 60 days from FERC’s March 1 order. (ISO-NE was granted a week extension to file them.) They would clarify that the relevant electric retail regulatory authority authorizes customers of small utilities to participate in a DER aggregation and that the RTO will resolve disputes that are within its authority and subject to its tariff.

The filing will also include an explanation of why ISO-NE’s proposal to require measurement of behind-the-meter DERs at the retail delivery point, rather than allowing submetering, minimizes barriers to entry for resources. The RTO has requested a rehearing of FERC’s rejection of its proposal to designate the DER aggregator as the entity responsible for providing any required metering information.

LS Power CSO Proposal

Finally, the committee rejected endorsing proposed tariff revisions by LS Power to allow its gas-fired Ocean State Power plant to unwind a 64-MW capacity increase while maintaining its existing 270-MW capacity supply obligation.

The plant had cleared Forward Capacity Auction 15 at 334 MW, but the company has become concerned that it will not be able to complete the uprate by the June 1, 2026, deadline. Under the RTO’s tariff, that would mean the plant would also lose its CSO for the existing capacity.

LS Power’s proposed revisions were intended to allow market participants to “unwind” promised capacity increases, allowing the plant to continue participating in the capacity market. Despite the RTO and its Internal Market Monitor opposing the proposal, the MC last month overwhelmingly endorsed it, with 83.3% in support. (See “LS Power’s Dilemma” in linked article above.)

But the company failed to achieve even a majority of the PC’s support, with only 45.7% voting in favor; it needed 60% for endorsement. All of the Generation sector was in favor, and minor support came from the Supplier, Alternative Resources and End User sectors. The Publicly Owned Entity sector was unanimous in opposition. Every sector had numerous abstentions.

LS Power may file a complaint with FERC under Federal Power Act Section 206. Before the vote, NEPOOL clarified to committee members that if they endorsed the revisions, it would indicate its support for LS Power’s revisions in the docket but not weigh in on the just and reasonableness of the current tariff.

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PNM, Avangrid Optimistic About Merger Prospects

While PNM Resources (NYSE: PNM) awaits a state Supreme Court decision that could give the company another shot at a merger with Avangrid (NYSE:AGR), PNM officials said they’ll keep running the company like it’s a standalone business.

The comments came Friday during a conference call with analysts to discuss PNM’s first-quarter results. Much of the discussion focused on Avangrid’s proposed acquisition of PNM, a deal that was announced in October 2020 and valued at $8.3 billion.

The merger received approval from five federal agencies and the Public Utility Commission of Texas, leaving approval from the New Mexico Public Regulation Commission (PRC) as the final hurdle to closing the merger. But in December 2021, the PRC voted 5-0 to reject the merger. (See NM Regulators Reject Avangrid-PNM Merger.)

PNM and Avangrid appealed the decision to the New Mexico Supreme Court. But the companies revised their strategy this year, when the PRC changed from a five-member elected commission to a three-member panel with commissioners appointed by Gov. Michelle Lujan Grisham. (See New NM Commissioner Steps Down over Qualifications.)

In March, the reconfigured PRC joined with PNM and Avangrid to file a motion asking the Supreme Court to dismiss the appeal and remand the case back to the PRC for rehearing.

On Friday, analysts pressed PNM officials for a timeline of the proceedings.

PNM Resources CEO Pat Vincent-Collawn emphasized that the court has no deadline for making a decision. Calling the state’s high court “the Supremes,” Vincent-Collawn referenced a song by the Motown musical group of the same name.

“You can’t hurry love … or mergers,” Vincent-Collawn told analysts.

Vincent-Collawn said that if the Supreme Court agrees to dismiss the appeal, the companies would file a motion for reconsideration of the merger with the PRC. The commission would establish a procedural schedule and decide whether to assign the case to a hearing examiner or manage it at the commission level.

PNM and Avangrid agreed last month to extend their merger agreement until July 20. That follows a decision last year to extend the merger agreement through April 20, 2023.

“This additional time should provide clarity on the path forward and an expected timeframe for further regulatory proceedings,” Vincent-Collawn said.

And for now, it’s business as usual at PNM, according to Don Tarry, the company’s president and chief operating officer.

“We’re focused on continuing to manage the business like it’s a stand-alone business,” Tarry said. “And we’ll continue to operate it that way and continue to fund it that way, too.”

Under the proposed acquisition, Avangrid would pay $50.30 in cash for each share of PNM Resources common stock. PNM Resources includes PNM, New Mexico’s largest electric utility, and TNMP, an electric transmission and distribution utility in Texas.

In discussing the proposed acquisition in a February conference call with analysts, Avangrid CEO Pedro Azagra said he expected the PRC’s new composition to make a difference. (See Avangrid Pushes Forward on NECEC, Offshore Wind, PNM Merger.) Azagra described the new commissioners as “highly experienced individuals” with “deep knowledge” of the energy transition and its challenges.

And in a news release last month announcing an extension of the merger agreement, Azagra said Avangrid remains committed to the merger.

“Together, we will accelerate Texas and New Mexico’s clean energy futures and increase the focus on reliability and resiliency for customers,” Azagra said.

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Wisconsin Tx Project Clears State Litigation

A transmission project that MISO approved 12 years ago cleared another legal hurdle Monday when a Wisconsin county judge found that regulators adequately scrutinized the project nearly four years ago.

Dane County Circuit Court Judge Jacob Frost upheld the Wisconsin Public Service Commission’s 2019 decision to issue a certificate of public convenience and necessity for the Cardinal Hickory Creek project, a 102-mile, 345-kV transmission line (2019CV003418).

The ruling does not affect last year’s U.S. district court decision, finding that federal agencies violated federal law when they cleared the line to route through the Upper Mississippi River National Fish and Wildlife Refuge. The decision halted construction on one segment of the line and is currently on appeal in the Seventh Circuit U.S. Court of Appeals. (See Federal Judge: Tx Line Can’t Cross Wildlife Refuge.)

Cardinal-Hickory Creek is one of the 17 Multi-Value Projects MISO approved as a $5-billion portfolio in 2011. The line is projected to facilitate the connection of nearly 20 GW of renewable energy, but it has been mired in litigation for more than a decade.

Frost said the Driftless Area Land Conservancy and two Wisconsin counties’ challenge to the PSC’s approval “largely boil down to disagreements with the PSC’s conclusions and decisions regarding the disputes of fact.” He said state regulators didn’t err in their decision to grant the certificate; adequately weighed competing evidence and explained their decision; properly determined that an environmental impact statement satisfied the state’s Environmental Policy Act; and did not shift the burden of proof to opponents of the line.

Regulators, not the courts, determine energy policy, Frost said.

“Though they couch the arguments as the PSC decision lacked substantial evidence, when examined more closely, petitioners are actually saying the PSC should not have believed the evidence applicants submitted and should have given greater weight to the evidence petitioners or PSC staff provide,” he wrote. “However, the court cannot second-guess the PSC as to weight and credibility of evidence. Because the PSC’s decision relied on substantial evidence, I must affirm.”

Frost said though he understood the “massive impacts” the project holds for Wisconsin, the PSC “properly conducted itself.”

The Cardinal-Hickory Creek owners, American Transmission, ITC Midwest and Dairyland Power Cooperative, said they were “extremely pleased” with the ruling.

“The judge’s decision reinforces that Cardinal-Hickory Creek is a critical, backbone project for the regional power grid within the Upper Midwest,” the companies said in a joint statement.

Mixed Responses

Jennifer Filipiak, executive director of the Driftless Area Land Conservancy, said the group was disappointed with the decision to uphold the PSC’s approval of the line. She said state regulators “failed to fully and fairly consider less-damaging alternatives to the Cardinal-Hickory Creek transmission line.”

“We remain committed to protecting the unique landscape of the Driftless Area and working to enhance its health and diversity. We are considering next steps and actions,” Filipiak said in a statement.

Wisconsin Wildlife Federation Executive Director Mark LaBarbera said his organization was similarly dissatisfied with the ruling. He said the PSC failed to “look more seriously” at potential alternatives and said that the line’s costs are already more expensive than original estimates.

“The company reported it has spent more than $530 million on this unfinished project, already exceeding its original $492 million total estimate,” LaBarbera said. “The dramatic cost increase makes clear why it’s essential to thoroughly study and consider alternatives before starting to build large projects that will damage Wisconsin’s natural environment. We are considering next steps and actions.”

Environmental Law & Policy Center senior attorney Brad Klein, who represented both conservation groups, said he is considering filing an appeal. He noted that the state decision does not impact the 2022 federal decision.

Clean Grid Alliance, Fresh Energy, and the Minnesota Center for Environmental Advocacy applauded the decision in a joint press release. They said that with the ruling, they’re “one step closer” to completing construction the project’s final leg so it can move forward and enable 115 renewable generation projects.

“We have been needing — and waiting — for this line for 12 years. And in that time, our society’s demand for clean electricity has grown even greater,” Clean Grid Alliance Executive Director Beth Soholt said. “Several states have enacted clean energy goals since 2011. That means we need this line — and much more — to meet their carbon reduction goals and improve the reliability of the grid to boot. There is great demand on our electric grid these days, so seeing Cardinal-Hickory Creek get across the finish line is a huge win.”

Amelia Vohs, regulatory attorney for the Minnesota Center for Environmental Advocacy, said the line is “well-designed and well-vetted to minimize its environmental impact, and its construction will result in reduced greenhouse gas emissions and more clean, renewable energy in the Midwest.”

“Everyone says they want a clean energy economy, but to get there we need transmission. You can’t have one without the other, and there is no time to waste,” Soholt said.

She noted that MISO’s first tranche of four long-term transmission portfolios, a $10 billion package approved last year, shows the need for transmission is only intensifying.

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Vistra Bolstering its Zero-carbon Generation

Vistra (NYSE:VST) officials told the financial community Tuesday that they are excited about the company’s recent acquisition of Energy Harbor, which will more than double its zero-carbon generation currently online and that they expect to close by year-end.

“We’ve talked about closing this in the fourth quarter, and I think that is achievable. So far, so good,” CEO Jim Burke told financial analysts during the company’s first-quarter earnings call.

The Irving, Texas-based company announced in March it was purchasing Energy Harbor, a spinoff from FirstEnergy (NYSE:FE), for $3 billion and assuming $430 million in debt. The company plans to combine Energy Harbor’s nuclear plants and its retail business in the MISO and PJM footprints with its nuclear, retail, renewables and battery storage assets into a new subsidiary called Vistra Vision. (See Vistra Pays more than $3 Billion for Energy Harbor.)

Burke said the regulatory approval process is progressing well and that the key filings have been made. The deal must be approved by the U.S. Department of Justice, FERC and the Nuclear Regulatory Commission.

“We believe the NRC is working towards an early October approval,” he said. “To be on the six-month track for a license transfer, we think, is actually on the more efficient side of the scale.”

Should the transaction close, it will give Vistra about 7.8 GW of zero-carbon generation and make it the second largest operator of nuclear plants in the U.S., with six reactors producing more than 6.3 GW of power. The Energy Harbor platform would also increase the company’s retail customer count to about 5 million.

“I like our retail, and we like our integrated model,” Burke said.

Vistra will add another 350 MW of zero-carbon energy when it completes the third phase of its Moss Landing energy storage facility in California later this summer.

The company reported quarterly ongoing operations adjusted EBITDA of $771 million, compared to $1.19 billion for the same period last year. It uses adjusted EBITDA as a performance measure because, it says, outside analysis of its business is improved by visibility into both net income prepared in accordance with GAAP and adjusted EBITDA.

Vistra’s share price closed Tuesday at $24.60, a gain of $1.22 for the day.